Methods and compositions for use of proppant surface chemistry and internal porosity to consolidate proppant particulates

ABSTRACT

Methods and compositions using surface chemistry and internal porosity of proppant particulates to consolidate the proppant particulates are described herein. The methods can include a method of gravel packing a wellbore. The method can include mixing an activator, a thickener, a crosslinker and a plurality of resin-coated proppant particulates to provide a gravel pack fluid and introducing the gravel pack fluid into a gravel pack region of the wellbore. The method can also include consolidating at least a portion of the plurality of resin-coated proppant particulates to provide a consolidated gravel pack, wherein the consolidated gravel pack has a UCS of at least about 60 psi when formed under a pressure of about 0.01 psi to about 50 psi and a temperature of about 160° F. to about 250° F.

FIELD

The present invention relates to methods for hydraulically fracturing asubterranean formation to improve the hydrocarbon production rates andultimate recovery by contacting unconsolidated resin-coated proppantparticulates with an activator to form a consolidated proppant pack. Thepresent invention also relates to methods for use in water injectionwells to consolidate the proppant particulates in a gravel packed orfrac packed region of a wellbore.

BACKGROUND

In order to stimulate and more effectively produce hydrocarbons from oiland gas bearing formations, and especially formations with low porosityand/or low permeability, induced fracturing (called “frac operations”,“hydraulic fracturing”, or simply “fracing”) of the hydrocarbon-bearingformations has been a commonly used technique. In a typical hydraulicfracturing operation, fluid slurries are pumped downhole under highpressure, causing the formations to fracture around the borehole,creating high permeability conduits that promote the flow of thehydrocarbons into the borehole. These frac operations can be conductedin horizontal and deviated, as well as vertical, boreholes, and ineither intervals of uncased wells, or in cased wells throughperforations.

In cased boreholes in vertical wells, for example, the high pressurefracturing fluids exit the borehole via perforations through the casingand surrounding cement, and cause the formations to fracture, usually inthin, generally vertical sheet-like fractures in the deeper formationsin which oil and gas are commonly found. These induced fracturesgenerally extend laterally a considerable distance out from the wellboreinto the surrounding formations, and extend vertically until thefractures reach a formation that is not easily fractured above and/orbelow the desired frac interval. The directions of maximum and minimumhorizontal stress within the formation determine the azimuthalorientation of the induced fractures.

The high pressure fracturing fluids contain particulate materials calledproppants. The proppants are generally composed of sand, resin-coatedsand or ceramic particulates, and the fluid used to pump these proppantparticulates downhole is usually designed to be sufficiently viscoussuch that the proppant particulates remain entrained in the fluid as itmoves downhole and out into the induced fractures. After the proppanthas been placed in the fracture and the fluid pressure relaxed, thefracture is prevented from completely closing by the presence of theproppants which thus provide a high conductivity flow path to thewellbore which results in improved production performance from thestimulated well.

Sometimes, a wellbore will need to be “gravel packed” before productionfrom the well begins in order to prevent particles (typically referredto as formation fines) from entering the wellbore. Gravel packing isnecessary in formations that contain individual sand grains that are nottightly cemented together. If the individual sand grains remainunconsolidated, when production of the formation begins, the force offluid flow will tend to move the unconsolidated sand grains into thewellbore. Gravel packing prevents this problem. In gravel packing,proppant is placed in the annulus of a wellbore, next to theunconsolidated formation fines, essentially working as a filter betweenthe wellbore and the formation. The proppant is oftentimes held in placeby a slotted screen which prevents the proppant (and formation fines)from migrating into the wellbore, while still allowing the formationfluids to do so. If the wellbore is cased, the casing is firstperforated in order to establish fluid communication between thewellbore and the formation. The gravel packing process is generallyperformed in all formations that are considered to have unconsolidatedformation fines, like those commonly found in the Gulf of Mexico.

Water injection wells can also be gravel packed because when a waterinjection well is shut-in, there can be a pressure surge or flowbackinto the wellbore which might result in an immediate flow of formationfines into the well. If formation fines are allowed to flow into thewell, the formation could become plugged, which would prevent theresumption of injection of water into the well.

Similarly, wellbores can also be “frac packed”. Frac packing involvesthe simultaneous hydraulic fracturing of a reservoir and the placementof a gravel pack in the annular region of the wellbore. In frac packing,a fracture is created using a high-viscosity fluid that is pumped intothe formation at above the fracturing pressure. Gravel pack screens arein place at the time of pumping and function the same way as in atypical gravel packing operation. Creating the fracture helps improveproduction and/or injection rates while the gravel pack preventsformation fines from being produced and the gravel pack screens preventthe proppant particulates from entering the produced fluids and/orflowback fluids. This method allows for high conductivity channels topenetrate deeply into the formation while leaving the area around thewellbore undamaged.

In each case, to maximize an increase in permeability and preventproppant flowback, the proppant particulates can be consolidated insidethe propped fracture or a gravel packed or frac packed region, forming a“proppant pack.” The proppant particulates can be consolidated by use ofactivators that react with the resin coating and cause consolidation ofthe proppant particulates. The activators are oftentimes mixed with thefracturing fluids and/or gravel pack fluids with the proppantparticulates entrained therein. However, the activators can also competewith other chemicals usually present in the fracturing fluids and/orgravel-pack fluids, such as thickening agents or crosslinkers, reducingthe effectiveness of any consolidation.

It is desirable to consolidate the proppant pack in the wellbore ondemand with an activator in a way that does not compete with otherchemicals, such as thickening agents, typically used in fracturingfluids and gravel-pack fluids. Therefore, a need exists for a method ofconsolidating a proppant pack downhole with an activator in the presenceof a thickening agent.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention may best be understood by referring to thefollowing description and accompanying drawings that are used toillustrate several exemplary embodiments of the invention. In thedrawings:

FIG. 1 depicts a perspective view of an illustrative gravel packassembly containing a proppant pack, according to several exemplaryembodiments of the present invention.

FIG. 2 depicts a cross-sectional view of the prepack screen taken alongline 1-1 of FIG. 1.

FIG. 3 depicts a perspective view of an illustrative prepack screenassembly containing a proppant pack, according to several exemplaryembodiments of the present invention.

FIG. 4 depicts a cross-sectional view of the prepack screen taken alongline 3-3 of FIG. 3.

FIG. 5 depicts a graphical representation showing the effect of proppantsize on Unconfined Compressive Strength (UCS).

FIG. 6 depicts a graphical representation showing the effect ofactivator concentration on Unconfined Compressive Strength (UCS).

FIG. 7 depicts a graphical representation showing the effect of theaddition of activator to cross-linked gel on a rheology profile of thecross-linked gel.

DETAILED DESCRIPTION

In the following description, numerous specific details are set forth.However, it is understood that embodiments of the invention may bepracticed without these specific details. In other instances, well-knownstructures and techniques have not been described in detail in order notto obscure the understanding of this description.

As described herein, the term “apparent specific gravity” is defined asthe weight per unit volume (grams per cubic centimeter) of proppantparticulates, including the internal porosity. The apparent specificgravity values given herein were determined by the Archimedes method ofliquid (water) displacement according to API RP60, a method which iswell known to those of ordinary skill in the art. For purposes of thisdisclosure, methods of testing the characteristics of the proppant interms of apparent specific gravity are the standard API tests that areroutinely performed on proppant samples.

As described herein, the term “substantially round and spherical” andrelated forms, is defined to mean an average ratio of minimum diameterto maximum diameter of about 0.8 or greater, or having an averagesphericity value of about 0.8 or greater compared to a Krumbein andSloss chart.

As described herein, the term “novolac resin” is defined as aphenol-formaldehyde resin (or phenolic resin) with a formaldehyde tophenol molar ratio of less than one.

As described herein, the term “cured” means a resin coating containingless than or equal to 50% curability as defined by the standard test foracetone extraction.

As described herein, the term “activator” means a chemical orcomposition that crosslinks or otherwise reacts with a resin coating toform a bond and/or consolidated proppant pack.

As used herein, the term “thickener” refers to a thickening agent,gelling agent, polymer, and/or linear gel.

As described herein, the term “crosslinker” means an element, metal,chemical, and/or composition that causes and/or encourages one or morecrosslinking reactions between two or more thickener molecules toprovide a crosslinked fluid.

As described herein, the terms “breaker” or “gel breaker” refer to achemical or agent that decreases the viscosity of a crosslinked gel orcrosslinked thickener molecules.

As described herein, the term “unconsolidated” means proppantparticulates that are not bonded to each other, either physically orchemically.

As described herein, the term “storage conditions” means temperatures ofup to 150° F. and atmospheric pressure.

As described herein, the term “wellbore conditions” means temperaturesof less than 220° F.

As described herein, the term “Unconfined Compressive Strength” (or“UCS”) is defined as the bond strength of a consolidated proppantparticulate sample and is measured in psi. Typically, a consolidatedproppant pack with a UCS of at least 20-100 psi within a hydraulicfracture will not flowback into the wellbore.

As described herein, the term “gravel pack region” means a region of awellbore that is adapted to contain a gravel pack.

As described herein, the term “frac pack region” means a region of awellbore and its surrounding formation that is adapted to contain a fracpack.

According to several exemplary embodiments of the present invention, aproppant composition is provided that includes a plurality ofunconsolidated particulates having a resin coating on the surface of theparticulates, such that chemically active amine sites remain on thesurface of the proppant particulates. The proppant composition canremain unconsolidated under storage conditions, inside a wellbore, andinside a subterranean fracture in the absence of an activator. Forexample, the proppant composition can remain unconsolidated in a gravelpack region or frac pack region in a wellbore in the absence of anactivator. According to several exemplary embodiments of the presentinvention, the proppant composition remains unconsolidated under storageconditions of temperatures of up to 150° F., up to 100° F., or up to 50°F. and atmospheric pressure from about one month to about eighteenmonths.

According to several exemplary embodiments of the present invention, amethod of hydraulic fracturing a subterranean formation is provided.According to several exemplary embodiments of the present invention, amethod of gravel packing a wellbore is provided. According to severalexemplary embodiments of the present invention, a method of frac packinga wellbore is provided. The methods can include mixing an activator witha liquid composition comprising water, a thickener, and a plurality ofresin-coated proppant particulates to provide a slurry, introducing theslurry into a subterranean fracture, a gravel pack region of thewellbore, and/or a frac pack region of the wellbore and consolidating atleast a portion of the plurality of resin-coated proppant particulatesto provide a consolidated proppant pack. The consolidated proppant packcan also be a gravel pack and/or a frac-pack. The consolidated proppantpack can have a UCS of at least about 60 psi when formed under apressure of about 0.01 psi to about 3,000 psi and a temperature of about32° F. to about 250° F.

According to several exemplary embodiments of the present invention, theproppant composition remains unconsolidated under wellbore conditions oftemperatures of up to 220° F., up to 200° F., up to 150° F., up to 100°F., or up to 50° F., and closure stress of up to 3,000 psi, up to 2,500psi, up to 2,000 psi, up to 1,500 psi, up to 1,000 psi, up to 500 psi,up to 300 psi, up to 150 psi, up to 75 psi, up to 50 psi, or up to 35psi. According to several exemplary embodiments, the proppantcomposition includes at least a portion thereof that remainsunconsolidated under wellbore temperatures from about 32° F., about 40°F., about 60° F., or about 80° F. to about 120° F., about 140° F., orabout 175° F. and under closure stress from about 5 psi to about 60 psi,about 10 psi to about 45 psi, or about 25 psi to about 40 psi.

According to several exemplary embodiments, the proppant compositionincludes any suitable proppant particulates. Suitable proppantparticulates can be any one or more of lightweight ceramic proppant,intermediate strength proppant, high strength proppant, natural fracsand, porous ceramic proppant, glass beads, natural proppant such aswalnut hulls, and any other manmade, natural, ceramic or glass ceramicbody proppants. According to several exemplary embodiments, the proppantparticulates include silica and/or alumina in any suitable amounts.According to several exemplary embodiments, the proppant particulatesinclude less than 80 wt %, less than 60 wt %, less than 40 wt %, lessthan 30 wt %, less than 20 wt %, less than 10 wt %, or less than 5 wt %silica based on the total weight of the proppant particulates. Accordingto several exemplary embodiments, the proppant particulates include fromabout 0.1 wt % to about 70 wt % silica, from about 1 wt % to about 60 wt% silica, from about 2.5 wt % to about 50 wt % silica, from about 5 wt %to about 40 wt % silica, or from about 10 wt % to about 30 wt % silica.According to several exemplary embodiments, the proppant particulatesinclude at least about 30 wt %, at least about 50 wt %, at least about60 wt %, at least about 70 wt %, at least about 80 wt %, at least about90 wt %, or at least about 95 wt % alumina based on the total weight ofthe proppant particulates. According to several exemplary embodiments,the proppant particulates include from about 30 wt % to about 99.9 wt %alumina, from about 40 wt % to about 99 wt % alumina, from about 50 wt %to about 97 wt % alumina, from about 60 wt % to about 95 wt % alumina,or from about 70 wt % to about 90 wt % alumina.

According to several exemplary embodiments, the proppant compositionincludes proppant particulates that are substantially round andspherical having a size in a range between about 6 and 270 U.S. Mesh.For example, the size of the particulates can be expressed as a grainfineness number (GFN) in a range of from about 15 to about 300, or fromabout 30 to about 110, or from about 40 to about 70. According to suchexamples, a sample of sintered particles can be screened in a laboratoryfor separation by size, for example, intermediate sizes between 20, 30,40, 50, 70, 100, 140, 200, and 270 U.S. mesh sizes to determine GFN. Thecorrelation between sieve size and GFN can be determined according toProcedure 106-87-S of the American Foundry Society Mold and Core TestHandbook, which is known to those of ordinary skill in the art.

According to several exemplary embodiments, the proppant compositionincludes proppant particulates having any suitable size. For example,the proppant particulates can have a mesh size of at least about 6 mesh,at least about 10 mesh, at least about 16 mesh, at least about 20 mesh,at least about 25 mesh, at least about 30 mesh, at least about 35 mesh,or at least about 40 mesh. According to several exemplary embodiments,the proppant particles have a mesh size from about 6 mesh, about 10mesh, about 16 mesh, or about 20 mesh to about 25 mesh, about 30 mesh,about 35 mesh, about 40 mesh, about 45 mesh, about 50 mesh, about 70mesh, or about 100 mesh. According to several exemplary embodiments, theproppant particles have a mesh size from about 4 mesh to about 120 mesh,from about 10 mesh to about 60 mesh, from about 16 mesh to about 20mesh, from about 20 mesh to about 40 mesh, or from about 25 mesh toabout 35 mesh.

According to several exemplary embodiments, the proppant compositionincludes proppant particulates having any suitable shape. The proppantparticulates can be substantially round, cylindrical, square,rectangular, elliptical, oval, egg-shaped, or pill-shaped. For example,the proppant particulates can be substantially round and spherical.According to several exemplary embodiments, the proppant particulates ofthe proppant composition have an apparent specific gravity of less than3.1 g/cm³, less than 3.0 g/cm³, less than 2.8 g/cm³, or less than 2.5g/cm³. According to several exemplary embodiments, the proppantparticulates have an apparent specific gravity of from about 3.1 to 3.4g/cm³. According to several exemplary embodiments, the proppantparticulates have an apparent specific gravity of greater than 3.4g/cm³, greater than 3.6 g/cm³, greater than 4.0 g/cm³, or greater than4.5 g/cm³.

According to several exemplary embodiments, the proppant composition canhave any suitable porosity. The proppant particulates can have aninternal interconnected porosity from about 1%, about 2%, about 4%,about 6%, about 8%, about 10%, about 12%, or about 14% to about 18%,about 20%, about 22%, about 24%, about 26%, about 28%, about 30%, about34%, about 38%, about 45%, about 55%, about 65%, or about 75% or more.In several exemplary embodiments, the internal interconnected porosityof the proppant particulates is from about 5% to about 75%, about 5% toabout 15%, about 10% to about 30%, about 15% to about 35%, about 25% toabout 45%, about 30% to about 55%, or about 35% to about 70%. Accordingto several exemplary embodiments, the proppant particulates can have anysuitable average pore size. For example, the proppant particulates canhave an average pore size from about 2 nm, about 10 nm, about 15 nm,about 55 nm, about 110 nm, about 520 nm, or about 1,100 to about 2,200nm, about 5,500 nm, about 11,000 nm, about 17,000 nm, or about 25,000 nmor more in its largest dimension. For example, the proppant particulatescan have an average pore size from about 3 nm to about 30,000 nm, about30 nm to about 18,000 nm, about 200 nm to about 9,000, about 350 nm toabout 4,500 nm, or about 850 nm to about 1,800 nm in its largestdimension.

The proppant particles can have any suitable surface roughness. Theproppant particles can have a surface roughness of less than 5 μm, lessthan 4 μm, less than 3 μm, less than 2.5 μm, less than 2 μm, less than1.5 μm, or less than 1 μm. For example, the proppant particles can havea surface roughness of about 0.1 μm to about 4.5 μm, about 0.4 μm toabout 3.5 μm, or about 0.8 pm to about 2.8 μm.

According to several exemplary embodiments of the present invention, theproppant particulates can be or include conventional pre-sinteredproppants. Such conventional proppants can be manufactured up to thesintering step according to any suitable process including, but notlimited to continuous spray atomization, spray fluidization, spraydrying, or compression. Suitable conventional proppants and methods fortheir manufacture are disclosed in U.S. Pat. Nos. 4,068,718, 4,427,068,4,440,866, 4,522,731, 4,623,630, 4,658,899, and 5,188,175, the entiredisclosures of which are incorporated herein by reference. The proppantparticulates can also be manufactured in a manner that creates porosityin the proppant grain. A process to manufacture a suitable porousceramic proppant is described in U.S. Pat. No. 7,036,591, the entiredisclosure of which is incorporated herein by reference. The proppantparticulates can also be manufactured according to any suitabledrip-casting process including, but not limited to the methods disclosedin U.S. Pat. Nos. 8,865,631, 8,883,693, and 9,175,210, and U.S. patentapplication Ser. Nos. 14/502,483 and 14/802,761, the entire disclosuresof which are incorporated herein by reference.

According to several exemplary embodiments, at least a portion of theproppant particulates of the proppant composition are coated with aresin material. According to several exemplary embodiments, at leastabout 50%, at least about 75%, at least about 85%, at least about 90%,at least about 95%, or least about 99% of the proppant particulates inthe proppant composition are coated with the resin material. Forexample, all of the proppant particulates in the proppant compositioncan be coated with the resin material.

According to several exemplary embodiments, at least a portion of thesurface area of each of the coated proppant particulates is covered withthe resin material. According to several exemplary embodiments, at leastabout 10%, at least about 25%, at least about 50%, at least about 75%,at least about 90%, at least about 95%, or at least about 99% of thesurface area of the coated proppant particulates is covered with theresin material. According to several exemplary embodiments, about 40% toabout 99.9%, about 85% to about 99.99%, or about 98% to about 100% ofthe surface area of the coated proppant particulates is covered with theresin material. According to several exemplary embodiments, the entiresurface area of the coated proppant particulates is covered with theresin material. For example, the coated proppant particulates can beencapsulated with the resin material.

According to several exemplary embodiments, the resin material ispresent on the proppant particulates in any suitable amount. Accordingto several exemplary embodiments, the resin coated proppant particulatescontain at least about 0.1 wt % resin, at least about 0.5 wt % resin, atleast about 1 wt % resin, at least about 2 wt % resin, at least about 4wt % resin, at least about 6 wt % resin, at least about 10 wt % resin,or at least about 20 wt % resin, based on the total weight of the resincoated proppant particulates. According to several exemplaryembodiments, the resin coated proppant particulates contain about 0.01wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt %, about 2.5 wt %,about 3.5 wt %, or about 5 wt % to about 8 wt %, about 15 wt %, about 30wt %, about 50 wt %, or about 80 wt % resin, based on the total weightof the resin coated proppant particulates.

According to several exemplary embodiments, the resin material includesany suitable resin. For example, the resin material can include aphenolic resin, such as a phenol-formaldehyde resin. According toseveral exemplary embodiments, the phenol-formaldehyde resin has a molarratio of formaldehyde to phenol (F:P) from a low of about 0.6:1, about0.9:1, or about 1.2:1 to a high of about 1.9:1, about 2.1:1, about2.3:1, or about 2.8:1. For example, the phenol-formaldehyde resin canhave a molar ratio of formaldehyde to phenol of about 0.7:1 to about2.7:1, about 0.8:1 to about 2.5:1, about 1:1 to about 2.4:1, about 1.1:1to about 2.6:1, or about 1.3:1 to about 2:1. The phenol-formaldehyderesin can also have a molar ratio of formaldehyde to phenol of about0.8:1 to about 0.9:1, about 0.9:1 to about 1:1, about 1:1 to about1.1:1, about 1.1:1 to about 1.2:1, about 1.2:1 to about 1.3:1, or about1.3:1 to about 1.4:1.

According to several exemplary embodiments, the phenol-formaldehyderesin has a molar ratio of less than 1:1, less than 0.9:1, less than0.8:1, less than 0.7:1, less than 0.6:1, or less than 0.5:1. Forexample, the phenol-formaldehyde resin can be or include a phenolicnovolac resin. Phenolic novolac resins are well known to those ofordinary skill in the art, for instance see U.S. Pat. No. 2,675,335 toRankin, U.S. Pat. No. 4,179,429 to Hanauye, U.S. Pat. No. 5,218,038 toJohnson, and U.S. Pat. No. 8,399,597 to Pullichola, the entiredisclosures of which are incorporated herein by reference. Suitableexamples of commercially available novolac resins include novolac resinsavailable from Plenco™, Durite® resins available from Momentive, andnovolac resins available from S.I. Group.

According to several exemplary embodiments, the phenol-formaldehyderesin has a weight average molecular weight from a low of about 200,about 300, or about 400 to a high of about 1,000, about 2,000, or about6,000. For example, the phenol-formaldehyde resin can have a weightaverage molecular weight from about 250 to about 450, about 450 to about550, about 550 to about 950, about 950 to about 1,500, about 1,500 toabout 3,500, or about 3,500 to about 6,000. The phenol-formaldehyderesin can also have a weight average molecular weight of about 175 toabout 800, about 700 to about 3,330, about 1,100 to about 4,200, about230 to about 550, about 425 to about 875, or about 2,750 to about 4,500.

According to several exemplary embodiments, the phenol-formaldehyderesin has a number average molecular weight from a low of about 200,about 300, or about 400 to a high of about 1,000, about 2,000, or about6,000. For example, the phenol-formaldehyde resin can have a numberaverage molecular weight from about 250 to about 450, about 450 to about550, about 550 to about 950, about 950 to about 1,500, about 1,500 toabout 3,500, or about 3,500 to about 6,000. The phenol-formaldehyderesin can also have a number average molecular weight of about 175 toabout 800, about 700 to about 3,000, about 1,100 to about 2,200, about230 to about 550, about 425 to about 875, or about 2,000 to about 2,750.

According to several exemplary embodiments, the phenol-formaldehyderesin has a z-average molecular weight from a low of about 200, about300, or about 400 to a high of about 1,000, about 2,000, or about 9,000.For example, the phenol-formaldehyde resin can have a z-averagemolecular weight from about 250 to about 450, about 450 to about 550,about 550 to about 950, about 950 to about 1,500, about 1,500 to about3,500, about 3,500 to about 6,500,or about 6,500 to about 9,000. Thephenol-formaldehyde resin can also have a z-average molecular weight ofabout 175 to about 800, about 700 to about 3,330, about 1,100 to about4,200, about 230 to about 550, about 425 to about 875, or about 4,750 toabout 8,500.

According to several exemplary embodiments, the phenol-formaldehyderesin has a polydispersity index from a low of about 1, about 1.75, orabout 2.5 to a high of about 2.75, about 3.5, or about 4.5. For example,the phenol-formaldehyde resin can have a polydispersity index from about1 to about 1.75, about 1.75 to about 2.5, about 2.5 to about 2.75, about2.75 to about 3.25, about 3.25 to about 3.75, or about 3.75 to about4.5. The phenol-formaldehyde resin can also have a polydispersity indexof about 1 to about 1.5, about 1.5 to about 2.5, about 2.5 to about 3,about 3 to about 3.35, about 3.35 to about 3.9, or about 3.9 to about4.5.

According to several exemplary embodiments, the phenol-formaldehyderesin has any suitable viscosity. The phenol-formaldehyde resin can be asolid or liquid at 25° C. For example, the viscosity of thephenol-formaldehyde resin can be from about 1 centipoise (cP), about 100cP, about 250 cP, about 500 cP, or about 700 cP to about 1,000 cP, about1,250 cP, about 1,500 cP, about 2,000 cP, or about 2,200 cP at atemperature of about 25° C. In another example, the phenol-formaldehyderesin can have a viscosity from about 1 cP to about 125 cP, about 125 cPto about 275 cP, about 275 cP to about 525 cP, about 525 cP to about 725cP, about 725 cP to about 1,100 cP, about 1,100 cP to about 1,600 cP,about 1,600 cP to about 1,900 cP, or about 1,900 cP to about 2,200 cP ata temperature of about 25° C. In another example, thephenol-formaldehyde resin can have a viscosity from about 1 cP to about45 cP, about 45 cP to about 125, about 125 cP to about 550 cP, about 550cP to about 825 cP, about 825 cP to about 1,100 cP, about 1,100 cP toabout 1,600 cP, or about 1,600 cP to about 2,200 cP at a temperature ofabout 25° C. The viscosity of the phenol-formaldehyde resin can also befrom about 500 cP, about 1,000 cP, about 2,500 cP, about 5,000 cP, orabout 7,500 cP to about 10,000 cP, about 15,000 cP, about 20,000 cP,about 30,000 cP, or about 75,000 cP at a temperature of about 150° C.For example, the phenol-formaldehyde resin can have a viscosity fromabout 750 cP to about 60,000 cP, about 1,000 cP to about 35,000 cP,about 4,000 cP to about 25,000 cP, about 8,000 cP to about 16,000 cP, orabout 10,000 cP to about 12,000 cP at a temperature of about 150° C. Theviscosity of the phenol-formaldehyde resin can be determined using aBrookfield viscometer.

According to several exemplary embodiments, the phenol-formaldehyderesin can have pH from a low of about 1, about 2, about 3, about 4,about 5, about 6, about 7 to a high of about 8, about 9, about 10, about11, about 12, or about 13. For example, the phenol-formaldehyde resincan have a pH from about 1 to about 2.5, about 2.5 to about 3.5, about3.5 to about 4.5, about 4.5 to about 5.5, about 5.5 to about 6.5, about6.5 to about 7.5, about 7.5 to about 8.5, about 8.5 to about 9.5, about9.5 to about 10.5, about 10.5 to about 11.5, about 11.5 to about 12.5,or about 12.5 to about 13.

According to several exemplary embodiments of the present invention, theresin coating applied to the proppant particulates is an epoxy resin.According to such embodiments, the resin coating can include anysuitable epoxy resin. For example, the epoxy resin can include bisphenolA, bisphenol F, aliphatic, or glycidylamine epoxy resins, and anymixtures or combinations thereof. An example of a commercially availableepoxy resin is BE188 Epoxy Resin, available from Chang Chun PlasticsCo., Ltd.

According to several exemplary embodiments, the epoxy resin can have anysuitable viscosity. The epoxy resin can be a solid or liquid at 25° C.For example, the viscosity of the epoxy resin can be from about 1 cP,about 100 cP, about 250 cP, about 500 cP, or about 700 cP to about 1,000cP, about 1,250 cP, about 1,500 cP, about 2,000 cP, or about 2,200 cP ata temperature of about 25° C. In another example, the epoxy resin canhave a viscosity from about 1 cP to about 125 cP, about 125 cP to about275 cP, about 275 cP to about 525 cP, about 525 cP to about 725 cP,about 725 cP to about 1,100 cP, about 1,100 cP to about 1,600 cP, about1,600 cP to about 1,900 cP, or about 1,900 cP to about 2,200 cP at atemperature of about 25° C. In another example, the epoxy resin can havea viscosity from about 1 cP to about 45 cP, about 45 cP to about 125 cP,about 125 cP to about 550 cP, about 550 cP to about 825 cP, about 825 cPto about 1,100 cP, about 1,100 cP to about 1,600 cP, or about 1,600 cPto about 2,200 cP at a temperature of about 25° C. The viscosity of theepoxy resin can also be from about 500 cP, about 1,000 cP, about 2,500cP, about 5,000 cP, or about 7,000 cP to about 10,000 cP, about 12,500cP, about 15,000 cP, about 17,000 cP, or about 20,000 cP at atemperature of about 25° C. In another example, the epoxy resin can havea viscosity from about 1,000 cP to about 12,000 cP, about 2,000 cP toabout 11,000 cP, about 4,000 cP to about 10,500 cP, or about 7,500 cP toabout 9,500 cP at a temperature of about 25° C. The viscosity of theepoxy resin can also be from about 500 cP, about 1,000 cP, about 2,500cP, about 5,000 cP, or about 7,500 cP to about 10,000 cP, about 15,000cP, about 20,000 cP, about 30,000 cP, or about 75,000 cP at atemperature of about 150° C. For example, the epoxy resin can have aviscosity from about 750 cP to about 60,000 cP, about 1,000 cP to about35,000 cP, about 4,000 cP to about 25,000 cP, about 8,000 cP to about16,000 cP, or about 10,000 cP to about 12,000 cP at a temperature ofabout 150° C.

According to several exemplary embodiments, the epoxy resin can have pHfrom a low of about 1, about 2, about 3, about 4, about 5, about 6,about 7 to a high of about 8, about 9, about 10, about 11, about 12, orabout 13. For example, the epoxy resin can have a pH from about 1 toabout 2.5, about 2.5 to about 3.5, about 3.5 to about 4.5, about 4.5 toabout 5.5, about 5.5 to about 6.5, about 6.5 to about 7.5, about 7.5 toabout 8.5, about 8.5 to about 9.5, about 9.5 to about 10.5, about 10.5to about 11.5, about 11.5 to about 12.5, or about 12.5 to about 13.

Methods for coating proppant particulates with resins are well known tothose of ordinary skill in the art, for instance see U.S. Pat. No.2,378,817 to Wrightsman, U.S. Pat. No. 4,873,145 to Okada and U.S. Pat.No. 4,888,240 to Graham, the entire disclosures of which areincorporated herein by reference.

According to one or more exemplary embodiments, any one or more of theproppant particulates can contain one or more chemical treatment agents.In one or more exemplary embodiments, the proppant particulates arecoated and/or encapsulated with one or more chemical treatment agents.For example, the chemical treatment agent can be directly and/orindirectly coated onto at least a portion of an outermost surface of theproppant particulates. In another example, the chemical treatment agentcan encapsulate the outermost surface of the proppant particulates. Thechemical treatment agent can also be contained within a coating thatcoats or encapsulates at least a portion of the proppant particulates.In one or more exemplary embodiments, the chemical treatment agent canalso be infused into any pores of the proppant particulates.

Suitable chemical treatment agents can be or include any one or more oftracers, scale inhibitors, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, paraffin or wax inhibitors,including ethylene vinyl acetate copolymers, asphaltene inhibitors,organic deposition inhibitors, biocides, demulsifiers, defoamers, gelbreakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers,iron scavengers, clay stabilizers, enzymes, biological agents,flocculants, naphthenate inhibitors, carboxylate inhibitors,nanoparticle dispersions, surfactants, combinations thereof, or anyother suitable oilfield chemical. In one or more exemplary embodiments,the scale inhibitor can inhibit scales of calcium, barium, magnesiumsalts and the like, including barium sulfate, calcium sulfate, andcalcium carbonate scales. The composites can further have applicabilityin the treatment of other inorganic scales, such as zinc sulfide, ironsulfide, etc. In one or more exemplary embodiments, the scale inhibitorsare anionic scale inhibitors. The scale inhibitors can include strongacids such as a phosphonic acid, phosphoric acid, phosphorous acid,phosphate esters, phosphonate/phosphonic acids, aminopoly carboxylicacids, chelating agents, and polymeric inhibitors and salts thereof. Thescale inhibitors can also include organo phosphonates, organo phosphatesand phosphate esters as well as the corresponding acids and saltsthereof. The scale inhibitors can also include polymeric scaleinhibitors, such as polyacrylamides, salts of acrylamido-methyl propanesulfonate/acrylic acid copolymer (AMPS/AA), phosphinated maleiccopolymer (PHOS/MA) or sodium salt of polymaleic acid/acrylicacid/acrylamido-methyl propane sulfonate terpolymers (PMA/AMPS). In oneor more exemplary embodiments, the scale inhibitors can include DTPA,(also known as diethylenetriaminepentaacetic acid;diethylenetriamine-N,N,N′,N′,N″-pentaacetic acid; pentetic acid;N,N-Bis(2-(bis-(carboxymethyl)amino)ethyl)-glycine; diethylenetriaminepentaacetic acid,[[(Carboxymethyl)imino]bis(ethylenenitrilo)]-tetra-acetic acid); EDTA:(also known as edetic acid; ethylenedinitrilotetraacetic acid; EDTA freebase; EDTA free acid; ethylenediamine-N,N,N′,N′-tetraacetic acid;hampene; Versene; N,N′-1,2-ethane diylbis-(N-(carboxymefhyl)glycine);ethylenediamine tetra-acetic acid); NTA, (also known asN,N-bis(carboxymethyl)glycine; triglycollamic acid; trilone A;alpha,alpha′,alpha″-trimethylaminetricarboxylic acid;tri(carboxymethyl)amine; aminotriacetic acid; Hampshire NTA acid;nitrilo-2,2′,2″-triacetic acid; titriplexi; nitrilotriacetic acid); APCA(aminopolycarboxylic acids); phosphonic acids; EDTMP(ethylenediaminetetramethylene-phosphonic acid); DTPMP (diethylenetriaminepentamethylenephosphonic acid); NTMP(nitrilotrimethylenephosphonic acid); polycarboxylic acids, gluconates,citrates, polyacrylates, and polyaspartates or any combination thereof.The scale inhibitors can also include any of the ACCENT™ scaleinhibitors, commercially available from The Dow Chemical Company. Thescale inhibitors can also include potassium salts of maleic acidcopolymers. In one or more exemplary embodiments, the chemical treatmentagent is DTPMP.

In one or more exemplary embodiments, the chemical treatment agent canbe or include any one or more demulsifying agents. The demulsifyingagents can include, but are not limited to, condensation polymers ofalkylene oxides and glycols, such as ethylene oxide and propylene oxidecondensation polymers of di-propylene glycol as well as trimethylolpropane; and alkyl substituted phenol formaldehyde resins, bis-phenyldiepoxides, and esters and diesters of same. The demulsifying agents canalso include oxyalkylated phenol formaldehyde resins, oxyalkylatedamines and polyamines, di-epoxidized oxyalkylated polyethers, polytriethanolamine methyl chloride quaternary, melamine acid colloid, andaminomethylated polyacrylamide.

In one or more exemplary embodiments, the chemical treatment agent canbe or include any one or more corrosion inhibitors. Suitable corrosioninhibitors can include, but are not limited to, fatty imidazolines,alkyl pyridines, alkyl pyridine quaternaries, fatty amine quaternariesand phosphate salts of fatty imidazolines. In one or more exemplaryembodiments, the chemical treatment agent can be or include any one ormore suitable foaming agents. Suitable foaming agents can include, butare not limited to, oxyalkylated sulfates or ethoxylated alcoholsulfates, or mixtures thereof In one or more exemplary embodiments, thechemical treatment agent can be or include any one or more suitableoxygen scavengers. Suitable oxygen scavengers can include triazines,maleimides, formaldehydes, amines, carboxamides, alkylcarboxyl-azocompounds cumine-peroxide compounds morpholino and amino derivativesmorpholine and piperazine derivatives, amine oxides, alkanolamines,aliphatic and aromatic polyamines.

In one or more exemplary embodiments, the chemical treatment agent canbe or include any one or more paraffin inhibitors. Suitable paraffininhibitors can include, but are not limited to, ethylene/vinyl acetatecopolymers, acrylates (such as polyacrylate esters and methacrylateesters of fatty alcohols), and olefin/maleic esters. In one or moreexemplary embodiments, the chemical treatment agent can be or includeany one or more asphaltene inhibitors. Suitable asphaltene inhibitorscan include, but are not limited to, asphaltene treating chemicalsinclude but are not limited to fatty ester homopolymers and copolymers(such as fatty esters of acrylic and methacrylic acid polymers andcopolymers) and sorbitan monooleate.

In one or more exemplary embodiments, the chemical treatment agent canbe or include a thermal neutron absorbing material. In one or moreexemplary embodiments, the thermal neutron absorbing material is boron,cadmium, gadolinium, iridium, samarium, or mixtures thereof. The thermalneutron absorbing material can leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, and leak from the proppant and into afracture, a formation, and/or a wellbore. A downhole tool emittingthermal neutrons can detect the presence of the thermal neutronabsorbing material to detect proppant placement, producing andnon-producing regions, and fracture size, shape, and location. Thedownhole tool can also detect the presence of the thermal neutronabsorbing material to detect the quality and percent fill of the gravelpack and/or the frac pack in the gravel pack and/or frac pack regions ofthe wellbore.

In one or more exemplary embodiments, the phenol-formaledehyde resinsand/or epoxy resins are semi-permeable such that one or more of thechemical treatment agents can leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the coated proppantparticulates at any suitable rate. According to one or more exemplaryembodiments, the chemical treatment agents can leach, elute, diffuse,bleed, discharge, desorb, dissolve, drain, seep, or leak from the coatedproppant particulates at a rate of at least about 0.1 parts-per-millionper gram of proppant particulates per day (expressed herein asppm/(gram*day)), at least about 0.5 ppm/(gram*day), at least about 1ppm/(gram*day), at least about 1.5 ppm/(gram*day), at least about 2ppm/(gram*day), at least about 3 ppm/(gram*day), at least about 5ppm/(gram*day), at least about 7 ppm/(gram*day), or at least about 10ppm/(gram*day) for at least about 2 months, at least about 6 months, atleast about 9 months, at least about 1 year, or at least about 2 years.For example, chemical treatment agents can elute from the coatedproppant particulates at a rate from about 0.01 ppm/(gram*day), about0.075 ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.25ppm/(gram*day), about 0.75 ppm/(gram*day), about 1.5 ppm/(gram*day),about 2.25 ppm/(gram*day), or about 3 ppm/(gram*day) to about 4ppm/(gram*day), about 5 ppm/(gram*day), about 6 ppm/(gram*day), about 7ppm/(gram*day), about 8 ppm/(gram*day), about 9 ppm/(gram*day), about 10ppm/(gram*day), about 20 ppm/(gram*day), about 30 ppm/(gram*day), orabout 50 ppm/(gram*day) for at least about 2 months, at least about 6months, at least about 9 months, at least about 1 year, or at leastabout 2 years.

According to several exemplary embodiments of the present invention, acuring agent is applied to the resin during coating of the proppantparticulates in order to accelerate the transition of the resin from aliquid to a solid state. Suitable curing agents include curing agentsthat will leave active amine or epoxy sites on the surface of the resincoating. Suitable curing agents will depend on the specific resinchemistry employed and can include amines, acids, acid anhydrides, andepoxies. In several exemplary embodiments of the present invention, aphenolic resin material is applied to the surface of the proppantparticulates and cured with an amine curing agent in order to leaveactive amine sites on the resin coated surface of the proppantparticulates. In several exemplary embodiments, the phenolic resin iscured with hexamethylenetetramine, also known as hexamine.

According to several exemplary embodiments, the epoxy resin can be curedwith an epoxy curing agent that leaves active epoxy sites on the resincoated surface of the proppant particulate. In one or more exemplaryembodiments, the epoxy resin can be cured with an epoxy curing agentthat leaves active curing agent functionality on the resin coatedsurface of the proppant particulate. Examples of commercially availableepoxy curing agents include Ancamine® 1638 and Ancamine® 2167, which areboth available from Air Products and Chemicals, Inc.

According to several exemplary embodiments, the resin coated proppantparticulates are cured in any suitable amounts. As used herein, the term“curability” refers to an amount in weight percent of the resin materialthat is not cured. The resin coated proppant particulates can have acurability of at least about 5 wt %, at least about 15 wt %, at leastabout 20 wt %, at least about 25 wt %, or at least about 30 wt %. Forexample, the resin coated proppant particulates can have a curability offrom about 5 wt % to about 45 wt %, from about 10 wt % to about 40 wt %,from about 20 wt % to about 38 wt %, from about 25 wt % to about 35 wt%, or from about 27 wt % to about 32 wt %.

According to several exemplary embodiments, the cured resin-coatedproppant composition is injected into a well during fracturingoperations via suspension in a fracturing fluid, and deposited intoinduced fractures. According to several exemplary embodiments of thepresent invention, the resin-coated proppant is injected into an annularregion outside of the wellbore, behind a gravel pack screen, viasuspension in a gravel pack fluid. According to several exemplaryembodiments, the cured resin-coated proppant composition is injectedinto a well during fracturing operations via suspension in a frac packfluid, and deposited into the wellbore and the induced fractures.Suitable fracturing fluids, gravel pack fluids, and frac pack fluids arewell known to those of ordinary skill in the art and can include guargum.

According to several exemplary embodiments of the present invention, theplurality of resin-coated proppant particulates residing in a proppedfracture or in a gravel packed or frac packed region of the wellbore arecontacted by an activator which cross-links with the resin-coatedproppant particulates in order to form a consolidated proppant pack.According to several exemplary embodiments of the present invention, theactivator is suspended in an unbroken fracturing fluid, gravel packfluid, or frac pack fluid along with the resin-coated proppantparticulates. According to several exemplary embodiments, the fracturingfluid, gravel pack fluid, and/or frac pack fluid includes from about oneto about two percent by weight of the activator. The fracturing fluid,gravel pack fluid, and frac pack fluid can be the same or at leastsubstantially equivalent to one another.

According to several exemplary embodiments, the fracturing fluidincludes any suitable amount of the activator. For example, thefracturing fluid can include about 0.01 wt %, about 0.05 wt %, about 0.1wt %, about 0.5 wt %, or about 1 wt % to about 1.5 wt %, about 2 wt %,about 2.5 wt %, about 3 wt %, about 5 wt %, or about 10 wt % of theactivator. The fracturing fluid can include about 0.025 wt % to about 8wt %, about 0.25 wt % to about 6 wt %, about 0.75 wt % to about 4 wt %,about 0.95 wt % to about 2.75 wt %, or about 1 wt % to about 2 wt % ofthe activator. An activator to resin weight ratio in the fracturingfluid can be about 0.001:1 to about 100:1, about 0.01 to about 50:1,about 0.05:1 to about 20:1, about 0.1:1 to about 10:1, about 0.5:1 toabout 5:1, about 0.8:1 to about 3:1, or about 0.9:1 to about 1.5:1.

According to several exemplary embodiments, the gravel pack fluidincludes any suitable amount of the activator. For example, the gravelpack fluid can include about 0.01 wt %, about 0.05 wt %, about 0.1 wt %,about 0.5 wt %, or about 1 wt % to about 1.5 wt %, about 2 wt %, about2.5 wt %, about 3 wt %, about 5 wt %, or about 10 wt % of the activator.The gravel pack fluid can include about 0.025 wt % to about 8 wt %,about 0.25 wt % to about 6 wt %, about 0.75 wt % to about 4 wt %, about0.95 wt % to about 2.75 wt %, or about 1 wt % to about 2 wt % of theactivator. An activator to resin weight ratio in the gravel pack fluidcan be about 0.001:1 to about 100:1, about 0.01 to about 50:1, about0.05:1 to about 20:1, about 0.1:1 to about 10:1, about 0.5:1 to about5:1, about 0.8:1 to about 3:1, or about 0.9:1 to about 1.5:1.

According to several exemplary embodiments, the frac pack fluid includesany suitable amount of the activator. For example, the frac pack fluidcan include about 0.01 wt %, about 0.05 wt %, about 0.1 wt %, about 0.5wt %, or about 1 wt % to about 1.5 wt %, about 2 wt %, about 2.5 wt %,about 3 wt %, about 5 wt %, or about 10 wt % of the activator. The fracpack fluid can include about 0.025 wt % to about 8 wt %, about 0.25 wt %to about 6 wt %, about 0.75 wt % to about 4 wt %, about 0.95 wt % toabout 2.75 wt %, or about 1 wt % to about 2 wt % of the activator. Anactivator to resin weight ratio in the frac pack fluid can be about0.001:1 to about 100:1, about 0.01 to about 50:1, about 0.05:1 to about20:1, about 0.1:1 to about 10:1, about 0.5:1 to about 5:1, about 0.8:1to about 3:1, or about 0.9:1 to about 1.5:1.

The activator can include any one or more suitable liquid epoxy resinsand solid epoxy resins. The activator can include any one or morebisphenyl A epoxy resins, modified bispheynl A epoxy resins, modifiedbisphenyl A/F epoxy resins, bispheynl F epoxy resins, and/or flexibleepoxy resins. The activator can include water dispersible liquid epoxyresins, water dispersible solid epoxy resins, amine-rich resins, andflexible epoxy resins and any mixture thereof. As used herein, the term“flexible epoxy resins” refers to epoxy resins having elastomeric chainsin their backbone. The elastomeric chains can include polyether chainsprepared from one or more alkylene oxides. In one or more embodiments,the flexible epoxy resin can include in its backbone ethylene oxide,propylene oxide or a mixture thereof.

Examples of suitable liquid epoxy resins are D.E.R.™ 317, D.E.R. 321,D.E.R. 331, D.E.R. 332, D.E.R. 351, D.E.R. 354, D.E.R. 3913, D.E.R. 732and D.E.R. 736, which are commercially available from Dow Chemical.Examples of an water dispersible liquid epoxy is D.E.R. 383 and XY92589.00, which is available from Dow Chemical, and EPOTUF 38-690, whichis available from Reichhold Inc. Examples of commercially availablewater dispersible solid epoxy resins include Ancarez® AR462 Resin andAncarez AR555 Epoxy Resin, which are available from Air Products andChemicals, Inc. and D.E.R. 671, D.E.R. 916 Epoxy Resins, which areavailable from Dow Chemical.

In one or more exemplary embodiments, the activator can be or includeany combination of D.E.R. 3913, D.E.R. 732, and/or D.E.R. 736. Forexample, the activator can be a two component blend of D.E.R. 3913 andD.E.R. 732. The activator can contain D.E.R. 3913 and D.E.R. 732 in anysuitable amounts. For example, the activator can contain from about 1 wt%, about 5 wt %, about 10 wt %, about 20 wt %, about 30 wt %, about 40wt %, or about 45 wt % to about 55 wt %, about 60 wt %, about 70 wt %,about 80 wt %, about 90 wt %, about 95 wt %, or about 99 wt % D.E.R.3913 and from about 1 wt %, about 5 wt %, about 10 wt %, about 20 wt %,about 30 wt %, about 40 wt %, or about 45 wt % to about 55 wt %, about60 wt %, about 70 wt %, about 80 wt %, about 90 wt %, about 95 wt %, orabout 99 wt % D.E.R. 732.

According to several exemplary embodiments, suitable activators forepoxy resins cured with an epoxy coating that leaves active epoxy siteson the resin coated surface of the proppant particulate include waterdispersible amine-rich resins. Examples of commercially available waterdispersible amine-rich resin activators include Anquamine® 701 andAnquawhite™ 100, which are both available from Air Products andChemicals, Inc., and EPOTUF 37-685, EPOTUF 37-667, and EPOTUF37-680available from Reichhold Inc. Suitable activators for epoxy resins curedwith an epoxy coating that leaves active epoxy sites on the resin coatedsurface of the proppant particulate can also include amine-rich resinsthat are not water soluble and/or not water dispersible, for example,Ancamine® 1638 and Ancamine 2167, which are both commercially availablefrom Air Products and Chemicals, Inc.

The activator can have any suitable viscosity. In one or more exemplaryembodiments, the activator has a viscosity from about 4, about 8, about12, about 20, or about 30 to about 35, about 45, about 55, about 65,about 75, or about 95 cSt at 25° C. in accordance with ASTM D445.

In one or more exemplary embodiments, the activator can be infused intoat least a portion of any one or more pores of one or more of theproppant particulates. The activator can be infused with or without theuse of a solvent. Methods for infusing a porous proppant particulate arewell known to those of ordinary skill in the art, for instance see U.S.Pat. No. 5,964,291 and U.S. Pat. No. 7,598,209, and similar processessuch as vacuum infusion, thermal infusion, capillary action, ribbonblending at room or elevated temperature, microwave blending or pug millprocessing can be utilized to infuse porous proppant particulates withan activator according to several exemplary embodiments of the presentinvention. It has been found that infusing the activator into pores ofthe proppant particulates can encourage the activator to stay on thesurface of the proppant particulates. Once the activator has eluted fromthe pores, most of the activator should remain at or near the proppantsurface(s) because the activator has a greater affinity for the resincoat of the proppant particulates than for the crosslinked fluid.

In one or more exemplary embodiments, the phenol-formaledehyde resinsand/or epoxy resins are semi-permeable such that the activator canleach, elute, diffuse, bleed, discharge, desorb, dissolve, drain, seep,or leak from the coated proppant particulates at any suitable rate.According to one or more exemplary embodiments, the activator can leach,elute, diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leakfrom the coated proppant particulates at a rate of at least about 0.1parts-per-million per gram of proppant particulates per day (expressedherein as ppm/(gram*day)), at least about 0.5 ppm/(gram*day), at leastabout 1 ppm/(gram*day), at least about 1.5 ppm/(gram*day), at leastabout 2 ppm/(gram*day), at least about 5 ppm/(gram*day), at least about15 ppm/(gram*day), at least about 50 ppm/(gram*day), or at least about100 ppm/(gram*day) for at least about 1 day, at least about 1 week, atleast about 1 month, at least about 2 months, or at least about 6months. For example, the activator can elute from the coated proppantparticulates at a rate from about 0.01 ppm/(gram*day), about 0.1ppm/(gram*day), about 0.5 ppm/(gram*day), about 1 ppm/(gram*day), about2 ppm/(gram*day), about 5 ppm/(gram*day), about 10 ppm/(gram*day), orabout 50 ppm/(gram*day) to about 55 ppm/(gram*day), about 65ppm/(gram*day), about 75 ppm/(gram*day), about 85 ppm/(gram*day), about100 ppm/(gram*day), about 125 ppm/(gram*day), about 150 ppm/(gram*day),about 200 ppm/(gram*day), about 300 ppm/(gram*day), or about 500ppm/(gram*day) for at least about 1 day, at least about 1 week, at leastabout 1 month, at least about 2 months, or at least about 6 months.

In one or more embodiments, the activator infused proppant particulatescan be uncoated (not coated with the resin material(s) disclosedherein). The uncoated infused particulates can be mixed with the resincoated particulates to provide a proppant mixture. About 10% of theparticulates of the proppant mixture can be the uncoated infusedparticulates. The uncoated infused particulates can have the one or morechemical treatment agents and/or the activator infused throughout, in atleast a portion of, or in an outer portion of its pores.

In one or more exemplary embodiments, the activator can leach, elute,diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leak fromthe uncoated proppant particulates at any suitable rate. According toone or more exemplary embodiments, the activator can leach, elute,diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leak fromthe uncoated proppant particulates at a rate of at least about 0.1ppm/(gram*day), at least about 0.5 ppm/(gram*day), at least about 1ppm/(gram*day), at least about 1.5 ppm/(gram*day), at least about 2ppm/(gram*day), at least about 5 ppm/(gram*day), at least about 15ppm/(gram*day), at least about 50 ppm/(gram*day), or at least about 100ppm/(gram*day) for at least about 1 day, at least about 1 week, at leastabout 1 month, at least about 2 months, or at least about 6 months. Forexample, the activator can elute from the coated proppant particulatesat a rate from about 0.01 ppm/(gram*day), about 0.1 ppm/(gram*day),about 0.5 ppm/(gram*day), about 1 ppm/(gram*day), about 2ppm/(gram*day), about 5 ppm/(gram*day), about 10 ppm/(gram*day), orabout 50 ppm/(gram*day) to about 55 ppm/(gram*day), about 65ppm/(gram*day), about 75 ppm/(gram*day), about 85 ppm/(gram*day), about100 ppm/(gram*day), about 125 ppm/(gram*day), about 150 ppm/(gram*day),about 200 ppm/(gram*day), about 300 ppm/(gram*day), or about 500ppm/(gram*day) for at least about 1 day, at least about 1 week, at leastabout 1 month, at least about 2 months, or at least about 6 months.

According to several exemplary embodiments of the present invention,both resin coated proppant particulates and uncoated proppantparticulates are suspended in a fracturing fluid, gravel pack fluid, orfrac pack fluid. The resin coated proppant particulates and uncoatedproppant particulates can be suspended in the fracturing fluid, gravelpack fluid, or frac pack fluid in any suitable amounts. For example, thefracturing fluid, gravel pack fluid, or frac pack fluid can includeabout 1 wt %, about 5 wt %, about 10 wt %, about 20 wt %, about 30 wt %,or about 40 wt % to about 50 wt %, about 60 wt %, about 70 wt %, about80 wt %, about 90 wt %, about 95 wt %, or about 99 wt % resin coatedproppant particulates and about 0.1 wt %, about 0.5 wt %, about 1 wt %,about 2 wt %, about 3 wt %, or about 5 wt % to about 8 wt %, about 10 wt%, about 12 wt %, about 15 wt %, or about 20 wt % uncoated proppantparticulates. The resin coated proppant particulates and uncoatedproppant particulates can be present in the fracturing fluid or gravelpack fluid with a uncoated proppant particulates to resin coatedproppant particulates weight ratio of about 0.001:1 to about 1:1, about0.05:1 to about 0.5:1, about 0.075:1 to about 0.25:1, about 0.1:1 toabout 0.2:1, or about 0.075:1 to about 0.15:1.

The uncoated proppant particulates can be infused with one or morechemical treatment agents and/or one or more activators. In one or moreexemplary embodiments, the uncoated proppant particulate portion of theconsolidated proppant pack can include at least about 1 wt %, at leastabout 2 wt %, at least about 5 wt %, at least about 10 wt %, at leastabout 20 wt %, at least about 30 wt %, at least about 50 wt %, or atleast about 75 wt % or more proppant particulates infused with the oneor more chemical treatment agents. In one or more exemplary embodiments,the uncoated proppant particulate portion of the consolidated proppantpack can include at least about 1 wt %, at least about 2 wt %, at leastabout 5 wt %, at least about 10 wt %, at least about 20 wt %, at leastabout 30 wt %, at least about 50 wt %, or at least about 75 wt % or moreproppant particulates infused with the activator.

According to several exemplary embodiments of the present invention,suitable activators can also be suspended in the fracturing fluid,gravel pack fluid, or frac pack fluid. The activators can be suspendedwith or in lieu of the activator infused proppant particulates.Commercially available examples of the resin coatings and activators arelisted above. The suitable activators can be suspended in the fracturingfluid, gravel pack fluid, or frac pack fluid in any suitable amounts.For example, the amine-cured phenolic resin compatible activators can bepresent in the fracturing fluid, gravel pack fluid, or frac pack fluidin amounts of about 0.01 wt %, about 0.05 wt %, about 0.1 wt %, about0.25 wt %, or about 0.5 wt % to about 1 wt %, about 1.5 wt %, about 2 wt%, about 2.5 wt %, about 5 wt %, or about 10 wt % based on the totalcombined weight of the fracturing fluid, gravel pack fluid, or frac packfluid, respectively. The fracturing fluid, gravel pack fluid, or fracpack fluid can include about 0.025 wt % to about 8 wt %, about 0.15 wt %to about 4 wt %, about 0.35 wt % to about 3.5 wt %, about 0.55 wt % toabout 2.75 wt %, or about 0.75 wt % to about 2 wt % amine-cured phenolicresin compatible activator. The epoxy resin compatible activators canalso be present in the fracturing fluid, gravel pack fluid, or frac packfluid in amounts of about 0.01 wt %, about 0.05 wt %, about 0.1 wt %,about 0.25 wt %, or about 0.5 wt % to about 1 wt %, about 1.5 wt %,about 2 wt %, about 2.5 wt %, about 5 wt %, or about 10 wt % based onthe total combined weight of the fracturing fluid, gravel pack fluid, orfrac pack fluid, respectively. The fracturing fluid, gravel pack fluid,or frac pack fluid can include about 0.025 wt % to about 8 wt %, about0.15 wt % to about 4 wt %, about 0.35 wt % to about 3.5 wt %, about 0.55wt % to about 2.75 wt %, or about 0.75 wt % to about 2 wt % of the epoxyresin compatible activator. The amine-cured phenolic resin compatibleactivators and epoxy resin compatible activators can be present in thefracturing fluid, gravel pack fluid, or frac pack fluid with anamine-cured phenolic resin compatible activator to epoxy resincompatible activator weight ratio of about 0.01:1 to about 20:1, about0.1:1 to about 10:1, about 0.5:1 to about 5:1, about 0.8:1 to about 3:1,or about 0.9:1 to about 1.5:1.

The fracturing fluid, gravel pack fluid, or frac pack fluid can includeany suitable thickener, such as a thickening agent, gelling agent,polymer, or linear gel. For example, the fracturing fluid, gravel packfluid, or frac pack fluid can include guar, guar gum, xanthan gum,mineral oil, locust bean gum, hydroxypropyl guar (HPG), carboxymethylguar (CMG), carboxymethylhydroxypropyl guar (CMHPG), starches,polysaccharides, alginates, mineral oils, cellulosic materials such ashydroxyethylcellulose (HEC), ethylcellulose, methylcellulose, sodiumcarboxymethylcellulose, hydroxypropylcellulose, hydroxyethylcellulose,and synthetic polymers such as polyacrylamides, and any combination ormixture thereof

The fracturing fluid, gravel pack fluid, or frac pack fluid can alsoinclude any suitable crosslinker. The crosslinker can be or includeboron, zirconium, titanium, chromium, iron, or aluminum or anycombination thereof. For example, the crosslinker can be or includeboric acid, disodium octaborate tetrahydrate, sodium diborate,pentaborates, ulexite, colemanite, zirconium lactate, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium malate, zirconium citrate, zirconium diisopropylamine lactate,titanium lactate, titanium malate, titanium citrate, titanium ammoniumlactate, titanium triethanolamine, titanium acetylacetonate, aluminumlactate, and aluminum citrate, and any combination or mixture thereof.The crosslinker can also be or include borate materials such asanhydrous sodium tetraborate.

The crosslinking reaction can be delayed by use of a buffer contained inthe fracturing fluid, gravel pack fluid, and/or frac pack fluid. Thebuffer can adjust the pH of the fluid to delay crosslinking for adesired period of time. For example, the buffer can adjust thefracturing fluid, gravel pack fluid, and/or frac pack fluid pH to fromabout 5.5, about 6, about 6.5, or about 6.8 to about 7.2, about 7.5,about 8, or about 8.5 to achieve a desired delay. In one or moreexemplary embodiments, the crosslinking can be delayed by about 1second, about 2 seconds, about 5 seconds, about 10 seconds, about 30seconds, about 1 minute, about 2 minutes, or about 4 minutes to about 6minutes, about 8 minutes, about 10 minutes, about 15 minutes, about 30minutes, or about 60 minutes. The crosslinking can be delayed by about 1second to about 5 minutes, from about 30 seconds to about 3 minutes, orfrom about 1 minute to about 2 minutes. In one or more exemplaryembodiments, the buffer can be or include one or more of sodiumcarbonate, sodium bicarbonate, sodium hydroxide, monosodium phosphate,formic acid, fumaric acid, hydrochloric acid, magnesium oxide, sodiumacetate, acetic acid, sulfamic acid, or the like. In one or moreexemplary embodiments, the crosslinker is a delayed crosslinker. Thedelayed crosslinker can be self-buffered and/or temperature activated.For example, the delayed crosslinker can be or include one or more ofBC-200, CL-23, or CL-24, commercially available from Halliburton EnergyServices, Inc. or YF100FlexD, which is commercially available fromSchlumberger Technology Corporation.

The fracturing fluid, gravel pack fluid, or frac pack fluid can alsoinclude any suitable breaker, such as a gel breaker. The breaker can beor include any type of oxidizing breaker. The breaker can be or includea persulfate, an encapsulated persulfate, or ammonia or any combinationor mixture thereof. For example, the breaker can be or include one ormore of SP breaker, ViCon NF breaker, Oxol II breaker, GBW-40 brekaer,or HT breaker commercially available from Halliburton Energy Services,Inc. The breaker can be used in combination with a catalyst toaccelerate the breaker activity. For example, the breaker can be used incombination with CAT-OS-1 and/or CAT-OS-2 catalyst commerciallyavailable from Halliburton Energy Services, Inc. In one or moreexemplary embodiments, the breaker can include metal halide salts, suchas lithium chloride (LiCl), sodium chloride (NaCl), potassium chloride(KCl), rubidium chloride (RbCl), or cesium chloride (CsCl), or anymixtures or combinations thereof. In one or more exemplary embodiments,the breaker can provide a fast break of the fracturing fluid, gravelpack fluid, or frac pack fluid. For example, a gel break time of thefracturing fluid, gravel pack fluid, or frac pack fluid of less than 48hours, less than 36 hours, less than 24 hours, less than 18 hours, lessthan 12 hours, less than 6 hours, less than 4 hours, less than 2 hours,or less than 1 hour.

The crosslinker, activator, thickener, breaker and proppant compositioncan be mixed or otherwise combined in any suitable manner and sequenceto provide the fracturing fluid, gravel pack fluid, and/or frac packfluid. In one or more exemplary embodiments, the fracturing fluid,gravel pack fluid, and/or frac pack fluid is obtained by providing anaqueous solution containing the activatorand the thickener, mixing theproppant composition and breaker with the aqueous solution to provide aslurry, and adding the crosslinker to the slurry to provide thefracturing fluid, gravel pack fluid, and/or frac pack fluid. In one ormore exemplary embodiments, the fracturing fluid, gravel pack fluid,and/or frac pack fluid is obtained by providing a slurry containing theproppant composition and the thickener, mixing the activator and breakerwith the slurry to provide an activated slurry, and adding thecrosslinker to the activated slurry to provide the fracturing fluid,gravel pack fluid, and/or frac pack fluid. In one or more exemplaryembodiments, the fracturing fluid, gravel pack fluid, and/or frac packfluid is obtained by providing an aqueous solution containing theactivator and the thickener, mixing the crosslinker and breaker with theaqueous solution to provide a base fluid, and adding the proppantcomposition to the base fluid to provide the fracturing fluid, gravelpack fluid, and/or frac pack fluid. In one or more exemplaryembodiments, the crosslinker is a delayed crosslinker that activates andcauses crosslinking when the fracturing fluid, gravel pack fluid, and/orfrac pack fluid is being pumped on the surface, is being pumped downholein a wellbore, is being placed into a gravel pack region and/or a fracpack region, and/or is being placed into a subterranean fracture. In oneor more explemplary embodiments, the breaker composition andconcentration rapidly reduces the fracturing fluid, gravel pack fluid,and/or frac pack fluid viscosity after the proppant is pumped into thefracture and gravel pack annulus, facilitating rapid proppant grain toproppant grain contact.

The fracturing fluid, gravel pack fluid, and/or frac pack fluid withsuspended resin-coated proppant particles and one or more suitableactivators can have any suitable viscosity and pH. For example, thefracturing fluid, gravel pack fluid, and/or frac pack fluid can have aviscosity of about 0.01 cP, about 0.05 cP, about 0.1 cP, about 0.5 cP,or about 1 cP to about 2 cP, about 3 cP, about 5 cP, about 7 cP, about10 cP, about 50 cP, about 100 cP, about 200 cP, about 500 cP, about1,000 cP, about 5,000 cP, or about 10,000 cP at a temperature of about25° C. The fracturing fluid, gravel pack fluid, and/or frac pack fluidcan have a pH of about 1 to about 2.5, about 2.5 to about 3.5, about 3.5to about 4.5, about 4.5 to about 5.5, about 5.5 to about 6.5, about 6.5to about 7.5, about 7.5 to about 8.5, about 8.5 to about 9.5, about 9.5to about 10.5, about 10.5 to about 11.5, about 11.5 to about 12.5, orabout 12.5 to about 13. The fracturing fluid, gravel pack fluid, and/orfrac pack fluid can remain pumpable for up to about 45 minutes, up toabout 1.5 hr, up to about 2 hr, up to about 4 hr, up to about 8 hr, upto about 12 hr, up to about 24 hr, or up to about 48 hr at temperaturesof about 100° F., about 130° F., or about 150° F. to about 175° F.,about 200° F., or about 220° F.

Due to the turbulent fluid flow associated with the injection of afracturing fluid, gravel pack fluid, and/or frac pack fluid into a wellbore, the consolidation reaction between the resin-coated proppantparticulates and the activator may not start immediately to anysubstantive degree. Once the resin-coated proppant particulates areplaced in the fractures or gravel packed or frac packed region, the wellcan be shut in, which allows the consolidation reaction between theresin-coated proppant particulates and the activator to begin. Accordingto several exemplary embodiments of the present invention, the well canbe shut in for about 4 hours up to one week, depending on the downholetemperature and pressure conditions. For example, the well can be shutin for about 5 hours, about 10 hours, about 15 hours, or about 24 hoursto about 2 days, about 3 days, about 5 days or about 7 days before theresin-coated proppant particulates are consolidated into a consolidatedproppant pack. One of ordinary skill in the art would be able todetermine how long the well needs to be shut in in order for theconsolidation reaction to take place at a given set of well conditions.

According to one or more embodiments, when the activator contacts theresin-coated proppant particulates, a crosslinking reaction occursbetween adjacent proppant particulates, which in turn then forms aconsolidated proppant pack. According to several exemplary embodimentsof the present invention, the resin-coated proppant particulates areconsolidated by bonding between the activator and proppant particulates,bonding of the proppant particulates to each other, or combinationsthereof. The consolidated proppant pack can include any amount of theresin coated proppant particulates. According to several exemplaryembodiments, at least about 50%, at least about 75%, at least about 85%,at least about 90%, at least about 95%, or least about 99% of theproppant particulates forming the consolidated proppant pack are coatedwith the resin material. In one or more exemplary embodiments, less thanabout 99%, less than about 95%, less than about 92%, less than about90%, or less than about 88% of the proppant particulates forming theconsolidated proppant pack are coated with the resin material. Forexample, the consolidated proppant pack can include at least about 1%,at least about 2%, at least about 5%, at least about 7%, at least about10%, at least about 12%, or at least about 15% uncoated proppantparticulates. The uncoated proppant particulates can be or include theporous proppant particulates infused with the one or more chemicaltreatment agents as described herein. The uncoated proppant particulatescan also be or include the porous proppant particulates infused with theactivator as described herein. In one or more exemplary embodiments, allof the proppant particulates in the proppant composition can be coatedwith the resin material.

Once the resin-coated proppant particulates are placed in the formation,gravel pack or frac pack, the fracturing fluid, gravel pack fluid,and/or frac pack fluid can be “broken”. Breaking the fracturing fluid,gravel pack fluid, and/or frac pack fluid can allow the fluid to beremoved from the fractures or gravel packed or frac packed region of thesubterranean formation without dislodging the consolidated proppantpack. In one or more exemplary embodiments, the activator does notinterfere with the breaking of the fracturing fluid. For example, thepresence of the activator can be inert to the breaking of the fracturingfluid.

In a gravel pack or frac pack situation, when the gravel pack fluidand/or frac pack fluid is broken, the proppant (or “gravel”) remainsbehind a gravel pack screen, while the broken gravel pack fluid and/orfrac pack fluid flows back into the wellbore. The screen worksessentially as a filter, leaving the consolidated proppant pack on oneside and allowing the broken gravel pack fluid and/or frac pack fluid toflow to the other.

The consolidated proppant pack can be utilized in a gravel pack regionor frac pack region of any suitable type of well. In one or moreexemplary embodiments, the consolidated proppant pack can be utilized ina gravel pack region or frac pack region of one or more of offshore oiland/or gas wells, onshore oil and/or gas wells, geothermal wells, waterwells, waste disposal wells, or water-injection wells. In the case ofwater injection wells, the consolidated proppant pack must havesufficient annular and fracture conductivity to minimize pressure dropover the pack during water injection and, at the same time, sufficientannular strength to prevent mobilization of the proppant and washoutsunder the water injection conditions that can exceed 1,250,000 gallonsof water per day. In one or more exemplary embodiments, the consolidatedproppant pack has suitable strength and conductivity to withstand about500,000, about 1,000,000, or about 1,200,000 to about 1,250,000, about1,500,000, or about 2,000,000 gallons of water per day under theformation fracture pressure or the pressure above which injection offluids will cause the subterranean formation to fracture hydraulically,flowing therethrough.

According to several exemplary embodiments of the present invention, amethod for the hydraulic fracturing of a subterranean formation isprovided. According to several exemplary embodiments of the presentinvention, a propped fracture is provided wherein a plurality ofunconsolidated resin-coated proppant particulates reside in at least aportion of the fracture. In accord with several exemplary embodiments ofthe present invention, an activator is introduced into the proppedfracture. Suitable activators are detailed above. When the activator isintroduced into the propped fracture, it contacts the resin-coatedproppant particulates. In several exemplary embodiments of the presentinvention, a consolidated proppant pack is formed as a result of thecontact between the resin-coated proppant particulates and theactivator. In several exemplary embodiments of the present invention,the resin-coated proppant particulates are consolidated by eitherphysical or chemical bonding, or combinations thereof.

According to several exemplary embodiments of the present invention, theconsolidated proppant pack can be formed in-situ under wellboreconditions. For example, the consolidated proppant pack can be formed bycontacting the resin-coated proppant particulates with the activatorunder a temperature of about 160° F., about 170° F., about 180° F.,about 185° F., or about 190° F. to about 195° F., about 200° F., about205° F., about 210° F., about 225° F., or about 250° F. According toseveral exemplary embodiments of the present invention, the consolidatedproppant pack can be formed by contacting the resin-coated proppantparticulates with the activator under a pressure of about 0.01 psi,about 0.5 psi, about 1 psi, about 5 psi, about 10 psi, or about 25 psito about 35 psi, about 45 psi, about 50 psi, or about 100 psi. Accordingto other exemplary embodiments of the present invention, theconsolidated proppant pack can be formed by contacting the resin-coatedproppant particulates with the activator under a pressure of about 10psi, about 50 psi, about 100 psi, about 250 psi, about 500 psi, or about750 psi to about 1,000 psi, about 1,500 psi, about 2,000 psi, or about5,000 psi. For example, the consolidated proppant pack can be formed bycontacting the resin-coated proppant particulates with the activatorunder a temperature of about 165° F. to about 230° F., about 175° F. toabout 220° F., about 193° F. to about 215° F., or about 197° F. to about207° F. and a pressure of about 2 psi to about 75 psi, about 5 psi toabout 60 psi, about 15 psi to about 50 psi, about 100 psi to about 1,000psi, or about 500 psi to about 5,000 psi.

According to several exemplary embodiments of the present invention, theproppant pack will remain unconsolidated until it is at least partiallycontacted by the activator. The consolidated proppant pack can have aUnconfined Compressive Strength (UCS) of at least about 4 psi, at leastabout 8 psi, at least about 20 psi, at least about 40 psi, at leastabout 60 psi, at least about 80 psi, at least about 100 psi, at leastabout 120 psi, at least about 150 psi, or at least about 200 psi under apressure of about 0.01 psi to about 50 psi and a temperature of about160° F. to about 250° F. The consolidated proppant pack can have a UCSof about 1 psi, about 5 psi, about 10 psi, about 25 psi, about 35 psi,about 50 psi, about 60 psi, about 75 psi, about 85 psi, or about 95 psito about 100 psi, about 120 psi, about 150 psi, about 175 psi, about 200psi, about 225 psi, about 250 psi, or about 500 psi under a pressure ofabout 0.01 psi, about 0.5 psi, about 1 psi, about 5 psi, about 10 psi,or about 25 psi to about 35 psi, about 45 psi about 50 psi, or about 100psi and a temperature of about 160° F., about 170° F., about 180° F.,about 185° F., or about 190° F. to about 195° F., about 200° F., about205° F., about 210° F., about 225° F., or about 250° F. A consolidatedproppant pack formed from a fracturing fluid containing from about 0.01wt % to about 0.5 wt % of an activator can have a UCS of about 10 psi toabout 100 psi or from about 25 psi to about 75 psi. A consolidatedproppant pack formed from a fracturing fluid containing from about 0.6wt % to about 1.4 wt % of an activator can have a UCS of about 100 psito about 250 psi or from about 115 psi to about 220 psi. A consolidatedproppant pack formed from a fracturing fluid containing from about 1.5wt % to about 2.5 wt % of an activator can have a UCS of about 250 psito about 400 psi or from about 300 psi to about 350 psi.

According to several exemplary embodiments of the present invention, aproppant composition can form a consolidated proppant pack after theproppant composition has been subjected to storage conditions oftemperatures of up to 150° F., up to 100° F., and up to 50° F. andatmospheric pressure from about one month to about eighteen months. Forexample, a proppant composition subjected to storage conditions oftemperatures of up to 150° F., up to 100° F., and up to 50° F. andatmospheric pressure from about one month to about eighteen months canform a consolidated proppant pack having a UCS the same as orsubstantially similar to a consolidated proppant pack formed from aproppant composition that has not been subjected to storage conditions.

According to several exemplary embodiments of the present invention, theconsolidated proppant pack can be contacted with or flushed with anysuitable gel-breaker material, such as metal halide salts. For example,the gel-breaker material can include lithium chloride (LiCl), sodiumchloride (NaCl), potassium chloride (KCl), rubidium chloride (RbCl), orcesium chloride (CsCl), or any mixtures or combinations thereof.Contacting the consolidated proppant pack with a gel-breaker materialcan increase the UCS of the consolidated proppant pack by at least about5%, at least about 10%, at least about 20%, at least about 30%, or atleast about 35%.

Further, pursuant to the present invention, a prepacked screen isprovided. According to several exemplary embodiments of the presentinvention, a prepacked screen is provided wherein a plurality ofunconsolidated resin-coated proppant particulates reside within at leasta portion of the screen prior to placement of the screen downhole. Theactivator can be introduced into the resin-coated proppant containingprepacked screen. Suitable activators are detailed above. According toone or more exemplary embodiments, when the activator contacts theresin-coated proppant particulates, a crosslinking reaction occursbetween adjacent proppant particulates, which in turn then form aconsolidated proppant pack within the prepacked screen assembly. Inseveral exemplary embodiments of the present invention, the resin-coatedproppant particulates are consolidated by either physical or chemicalbonding, or combinations thereof

FIG. 1 depicts a perspective view of an illustrative gravel packassembly 100 containing a consolidated proppant pack 110. As shown inFIG. 1, the gravel pack assembly 100 can include a casing 102 and atubular 104. The tubular 104 can be axially aligned within the casing102, resulting in an annular space 112 situated between the tubular 104and the casing 102. The tubular 104 can have a perforated section (notshown) and at least a portion of the perforated section can besurrounded by a screen 106. For example, the screen 106 can becircumferentially disposed about the perforated section and axiallyaligned with tubular 102. The consolidated proppant pack 110 can be atleast partially located in the annular space 112, between the screen 106and the casing 102. The casing 102 can include one or more perforations(not shown) for providing fluid communication between a surroundingsubterranean environment and the consolidated proppant pack 110. Thegravel pack assembly 100 can be located in any suitable vertical orhorizontal wellbore. A longitudinal axis of the gravel pack assembly 100can have any suitable orientation with respect to vertical. For example,the longitudinal axis of the tubular 104 can be substantially verticallyoriented or substantially horizontally oriented. In one or moreexemplary embodiments, the gravel pack assembly 100 can be located in avertical portion, deviated portion, and/or horizontal portion ofwellbore. In one or more exemplary embodiments, two or more gravel packassemblies 100 can be located in a single wellbore. In one or moreexemplary embodiments, the wellbore can be an openhole, or uncased,wellbore (not shown). For example, the consolidated proppant pack 110can be positioned in an openhole wellbore (not shown) and theconsolidated proppant pack 110 can be disposed adjacent to and/or incontact with the surrounding subterranean environment.

FIG. 2 depicts a cross-sectional view of the gravel pack assembly 100taken along line 1-1 of FIG. 1. As shown in FIG. 2, a second annulus 108can be formed between the tubular 104 and the screen 106. A plurality oflongitudinally arranged rods 112 can be disposed about the consolidatedtubular 104 such that the screen 106 is at least partially offset fromthe tubular 104. The rods 112 can be spaced apart from one another andarranged coaxially with the tubular 104. The screen 106 can be wrappedaround the rods 112 and welded to the tubular 102.

FIG. 3 depicts a perspective view of an illustrative prepack screenassembly 300 containing a consolidated proppant pack 310. As shown inFIG. 3, the prepack screen assembly 300 can include a tubular 302 havinga perforated section 304. At least a portion of the perforated section304 can be surrounded by a screen 306. For example, the screen 306 canbe circumferentially disposed about the perforated section 304 andaxially aligned with tubular 302. An annulus 308 can be formed betweenthe tubular 302 and the screen 306. A consolidated proppant pack 310 canbe disposed between the tubular 302 and the screen 306, in the annulus308. A plurality of longitudinally arranged rods 312 can be disposedabout the consolidated proppant pack 310 such that the screen 306 is atleast partially offset from the consolidated proppant pack 310. The rods312 can be spaced apart from one another and arranged coaxially with thetubular 302. The screen 306 can be wrapped around the rods 312 andwelded to the tubular 302 via welds 314. The tubular 302 can include athreaded portion 316 on at least one end thereof for connecting theprepack screen assembly 300 to production tubing (not shown), forexample. FIG. 4 depicts a cross-sectional view of the prepack screentaken along line 4-4 of FIG. 3. Examples of prepack screen assembliescan be found in U.S. Pat. Nos. 4,487,259 and 5,293,935, the entiredisclosures of which are incorporated herein by reference.

The consolidated proppant pack 310 can be consolidated before, during,or after inclusion of the proppant particulates in the annulus 308. Forexample, loose, unconsolidated resin-coated proppant particulates can beintroduced to the annulus 308 of the prepack screen assembly 300. Afterintroduction of the resin-coated proppant particulates to the annulus308, the activator can contact the resin-coated proppant particles toproduce the consolidated proppant pack 310. After completion of theprepack screen assembly 300 at the surface, the pre-pack assembly 300can be lowered downhole to a desired depth.

Further, pursuant to the present invention, a remedial workoverprocedure (not shown) for replacement of a gravel pack screen assemblyis provided. According to several exemplary embodiments of the presentinvention, a gravel pack screen located downhole in a gravel pack regionof a wellbore is removed from the wellbore with a downhole tool. Afterremoval of the screen, a plurality of unconsolidated resin-coatedproppant particulates in a fracturing fluid, gravel pack fluid, and/orfrac pack fluid can be placed in the gravel pack region. The activatorin the fluid then contacts the resin-coated proppant particulates,causing a crosslinking reaction between adjacent proppant particulates,which in turn then form a consolidated proppant pack within the gravelpack region, forming a plug in the wellbore to block fluid communicationbetween the subterranean formation and the surface. In several exemplaryembodiments of the present invention, a drill is then lowered into thewellbore to drill a borehole within the consolidated proppant pack plugand to reestablish fluid communication with the subterranean formation.

Other exemplary embodiments include injecting and consolidating theproppant in caverns or voids located behind a casing that can extendinto a formation, injecting and consolidating the proppant into shallow,low-pressure well fractures, and placing zonal isolation plugs formedfrom the consolidated proppant. Other exemplary embodiments can alsoinclude forming and placing the consolidated proppant into and/or aroundperforations through a well casing to provide filtration and sandcontrol for fluid flow through the perforations that provide fluidcommunication between the formation and the wellbore.

The following examples are illustrative of the compositions and methodsdiscussed above.

EXAMPLES

Several commercially available water dispersible epoxy resins are listedin Table 1. These water dispersible epoxy resins are representative ofthe class of epoxy resins that may be suitable for use as an activatorin several exemplary embodiments of the present invention, but are notintended to be exhaustive.

TABLE 1 Sample Name Composition Ancarez AR555 Epoxy Oxirane, 2,2,′-[(1-Resin (available from methylethylidene)bis(4,1- Air Productsphenyleneoxymethylene)]bis-homopolymer and Chemicals, Inc.) (50-60%)Water (40-50%) Ancarez AR462 Resin Bisphenol A diglycidyl ether resin(55-65%) (available from Air Water (35-45%) Products and Chemicals,Inc.) D.E.R. 916 Epoxy Resin Modified, semi-solid, epoxy novolac resin(available from Dow Reaction product of phenol-formaldehyde Chemical)novolac with epichlorohydrin emulsified in water XZ 92598.00Experimental Propane, 2,2-bis[p-(2,3- Liquid Epoxy Resinepoxypropoxy)phenyl]-,polymers (40-60%) Emulsion (available from Water(20-40%) Dow Chemical) Nonionic surfactant (<10%) D.E.R. 3913 EpoxyResin Modified epoxy resin (30-50%); (available from Dow Propane,2,2-bis[p-(2,3- Chemical) epoxypropoxy)phenyl]-,polymers (25-45%);Reaction product: Bisphenol F- (epichlorhydrin) (<15%); Alkyl (C₁₂₋₁₄)glycidyl ether (<10%)

The experiments described below were carried out using exemplarymaterials in order to determine the compatibility of the epoxy resinswith fracturing fluids. These experiments are meant to be illustrativeof exemplary embodiments of the present invention and are not intendedto be exhaustive.

Fracturing Fluid Compatibility Testing

According to several exemplary embodiments of the present invention, anactivator is injected into a fracture, gravel pack or frac pack alongwith a fracturing fluid in order to contact resin-coated proppantparticulates residing in the fracture, gravel pack or frac pack.Therefore, according to such embodiments, it is desirable that theactivator is compatible with, or has minimal chemical interaction with,the fracturing fluid so that the activator retains its activity until itreaches the resin-coated proppant particulates residing in the fracture,gravel pack or frac pack. Accordingly, four epoxy resin samples weretested for their compatibility with a fracturing fluid.

First, a fracturing fluid was prepared by weighing out 1500 g ofdeionized water into a 2L beaker. To provide gel clean-up, 30.0 g of KClwas added to the water using an overhead stirrer and was mixed untilcompletely dissolved. 7.2 g of guar gum, a thickening agent, was thenslowly added to the vortex and the pH of the solution was adjusted (with1N HCl or NaOH as necessary) to reach a pH of between 5-7. The mixturewas then stirred for 15 minutes. The fracturing fluid was then allowedto hydrate for at least four hours by allowing the fracturing fluid tosit quiescent at ambient temperature. After hydration, the pH of thefracturing fluid was adjusted to 10.1-10.5 with 1N NaOH to condition thefluid as necessary.

Four activators were then labeled “AR555”, “AR462”, “DER 916”, and “DER3913” to represent the epoxy dispersions listed in Table 1, and 500 g ofthe fracturing fluid was placed into each beaker. 5.0 g of each epoxydispersion (or 1% by weight) was added to the appropriate activator andthe components were mixed. Then, 200.0 g of each fracturingfluid/dispersion mixture was placed into a blender jar and was blendeduntil a vortex formed. Next, 0.12 g of ammonium peroxydisulfate, ALSgrade 98% minimum, which is commercially available from Alfa Aesar®, wasadded to the blender to function as a fracturing fluid breaker. Themixtures were stirred for 15 seconds. Then, 192.0 g of CARBOBOND® LITE®20/40 resin-coated lightweight ceramic proppant which is commerciallyavailable from CARBO Ceramics, Inc. was added to the mixtures andstirred until a vortex is formed. Finally, 0.1 g of sodium tetraboratepentahydrate fracturing fluid crosslinker, which is commerciallyavailable from Fritz Industries®, was added to the mixtures.

The samples were heated on a hotplate to approximately 180° F. with anoverhead stirrer in order to break the fracturing fluid. The sampleswere then placed in a water bath heated to 194° F. for 90 minutes. After90 minutes, the samples were allowed to cool to room temperature and thebroken fracturing fluid was decanted off the proppant particulates. Aviscosity measurement of the samples was then taken using a Fann Model35A viscometer with a B-2 bob. A viscosity of less than 20 cP at roomtemperature is considered to indicate that the activator is compatiblewith the fracturing fluid. Table 2 summarizes the viscosity results forthe four prepared samples.

TABLE 2 Viscosity at Room Temperature Temperature Sample (cP) pH (° F.)Ancarez AR555 2.5 9 75 Epoxy Resin Ancarez AR462 2.5 9 75 Resin D.E.R.916 2.5 9 75 Epoxy Resin D.E.R. 3913 2.5 9 75 Epoxy Resin

A second experiment was performed using the above procedure, except thatthe composition included 2% by weight of the epoxy dispersion (10.0 gadded to 500 g of fracturing fluid). According to this experiment,Ancarez AR555 Epoxy Resin, Ancarez AR462 Resin, D.E.R. 916 Epoxy Resin,and epoxy resin emulsion XZ 92598.00 Experimental Liquid Epoxy Resin,commercially available from Dow Chemical, were tested. Table 3summarizes the viscosity results for these four samples.

TABLE 3 Viscosity at Room Temperature Temperature Sample (cP) pH (° F.)Ancarez AR555 2.5 9 75 Epoxy Resin Ancarez AR462 2.5 9 75 Resin D.E.R.916 2.5 9 75 Epoxy Resin XZ 92598.00 2.5 9 75 Experimental Liquid EpoxyResin EmulsionUCS Testing (using 40 Pounds of Borate-Crosslinked Fracturing Fluid)

The experiments described below were performed with exemplary materialsin order to determine the UCS of certain resin-coated proppants afterconsolidation. These experiments are meant to be illustrative ofexemplary embodiments of the present invention and are not intended tobe exhaustive. These experiments were designed to simulate actualdownhole conditions.

Four fracturing fluid proppant samples which included 1% by weight ofthe epoxy dispersion were prepared using the procedure described above,except that the fracturing fluid was not decanted from the proppantparticulates. A proppant slug of each of the four samples (Ancarez®AR555 Epoxy Resin, Ancarez® AR462 Resin, D.E.R.™ 916 Epoxy Resin, andD.E.R.™ 3913 Epoxy Resin) was loaded into the metallic cylinder of a UCScell and the fracturing fluid was broken. The bottom valves of the UCScells were closed, but the top valves were left open to simulate a zerostress environment. The proppant slugs were not rinsed. The UCS cellswere placed in an oven at 200° F. for 64 hours. After 64 hours, the UCScells were removed from the oven and the proppant slugs were placed in adesiccator to dry overnight. The resultant proppant slugs were preparedfor testing by filing the edges perpendicular to the sides. The slugswere then crushed using an Admet Universal Testing Machine with DualColumn, model eXpert 2600, with a 2000 pound load cell. The proppantslugs were subjected to a compressive load at a rate of 0.1 in/min andthe UCS is the measurement of the compressive load at the point ofbreakage divided by the area of the proppant slug. Table 4 summarizesthe results of the UCS test on the four prepared samples.

TABLE 4 UCS, psi Sample (Zero Stress, 200° F.) Ancarez AR555 20 EpoxyResin Ancarez AR462 20 Resin D.E.R. 916 29 Epoxy Resin D.E.R. 3913 60Epoxy Resin

A second UCS experiment was conducted, except that the compositionsincluded 2% by weight of the epoxy dispersion. According to thisexperiment, Ancarez AR555 Epoxy Resin, Ancarez AR462 Resin, D.E.R. 916Epoxy Resin, and epoxy emulsion XZ92598 Experimental Liquid Epoxy ResinEmulsion were tested. Table 5 summarizes the results of the UCS test onthe four samples.

TABLE 5 Typical length under UCS, psi Length UCS conditions at Sample(Zero Stress, 200° F.) (in.) 1000 psi Ancarez AR555 70 3.25 2.12-2.25Epoxy Resin Ancarez AR462 201 3.25 2.12-2.25 Resin D.E.R. 916 57 3.252.12-2.25 Epoxy Resin XZ 92598.00 117 3.25 2.12-2.25 Experimental LiquidEpoxy Resin EmulsionUCS Testing (using 80 pounds of HEC Fracturing Fluid)

A UCS experiment was conducted using D.E.R. 3913 Epoxy Resin in 80pounds of HEC (Hydroxyethylcellulose) fracturing fluid. The 80 pounds ofHEC fracturing fluid was prepared by weighing out 1000 g of deionizedwater into a 2 L beaker. 24 mL of the HEC concentrated suspension wasadded to the water using an overhead stirrer and was mixed untilcompletely dissolved. The pH was then adjusted to a pH of 8-9 with 1NNaOH. The solution was allowed to reach full viscosity within a minuteor two with constant stirring. Next, 15 mL of Vicon NF, a fracturingfluid that is commercially available from Halliburton Energy Services,Inc., was added to act as a fracturing fluid breaker. 20.0 mL of D.E.R.3913 Epoxy Resin (or 2% by volume) was added to the fracturing fluid toact as an activator. 66.0 g of CARBOBOND LITE 20/40 resin-coatedlightweight ceramic proppant which is commercially available from CARBOCeramics, Inc., was added to a clean beaker. 80 mL of the preparedfracturing fluid was added. Using an overhead stirrer, theproppant/fluid mixture was mixed for 1 minute. The proppant/fluidmixture was then transferred to a UCS cell and the fracturing fluid wasdrained out through the bottom valve. The valves on the UCS cells wereleft open to simulate a zero stress environment. The unpressurized UCScell was then placed in an oven set at 200° F. for 24 hours. A secondset of UCS experiments was repeated using the same procedure above butwith a 2% KCl rinse. After the proppant/fluid mixture was transferred toa UCS cell and the fracturing fluid drained out, the proppant pack inthe UCS cell was flushed with 2% KCl (in deionized water). Theunpressurized UCS cell was then placed in an oven set at 200° F. for 24hours. After 24 hours, the cells were removed from the oven, theproppant slugs were removed from the UCS cell and the proppant slugswere allowed to cool and dry for at least 24 hours. The resultantproppant slugs were prepared for testing by filing the edgesperpendicular to the sides. The slugs were then crushed using an AdmetUniversal Testing Machine with Dual Column, model eXpert 2600, with a2000 pound load cell. The proppant slugs were subjected to a compressiveload at a rate of 0.1 in/min and the UCS is the measurement ofcompressive load at the point of breakage divided by the area of theproppant slug. Unexpectedly, the 2% KCl rinse increased the UCS of thesample. Table 6 summarizes the results of the UCS test on these preparedsamples.

TABLE 6 KCl Rinse UCS, psi Sample Proppant Type (mL) (Zero Stress, 200°F.) D.E.R 3913 CARBOBOND 0 237 Epoxy Resin LITE20/40 D.E.R. 3913CARBOBOND 100 328 Epoxy Resin LITE 20/40

A third set of UCS experiments using the 80 pound HEC Fracturing Fluidwas conducted on CARBOBOND LITE 16/20 resin-coated lightweight ceramicproppant which is commercially available from CARBO Ceramics, Inc. in asimilar manner as mentioned above. Table 7 summarizes the results of theUCS test on these prepared samples. The KCL rinse also increased the UCSof the sample.

TABLE 7 KCl Rinse UCS, psi Sample Proppant Type (mL) (Zero Stress, 200°F.) D.E.R. 3913 CARBOBOND 0 172 Epoxy Resin LITE 16/20 D.E.R. 3913CARBOBOND 100 210 Epoxy Resin LITE 16/20

The effect of the size of the proppant particulates on UCS strength isshown in FIG. 3. The reduction in UCS strength when going from proppantwith a mesh size distribution between 20/40 to proppant with a mesh sizedistribution between 16/20 is observed. This result is expected due tothe reduced points of contact that result from larger particles. Despitethe increase in proppant size, the 16/20 mesh proppant still exhibitsrelatively high UCS strength.

A fourth set of UCS experiment using the 80 pound HEC Fracturing Fluidwas conducted on CARBOBOND LITE 20/40 resin-coated lightweight ceramicproppant, which is commercially available from CARBO Ceramics, Inc., ina similar manner as mentioned above but with different activatorloadings (0 vol %, 0.5 vol %, 1 vol % and 2 vol %). The plot shown inFIG. 4 summarizes the results of the UCS test on these prepared samples.

130° F. Storage Stability Test

In order to test whether or not the resin-coated proppant particulateswould consolidate or the finished properties would change under elevatedstorage conditions in the absence of an activator, samples of CARBOBONDLITE 20/40 resin-coated lightweight ceramic proppant, which iscommercially available from CARBO Ceramics, Inc., were heated in an ovenset at 130° F. for a duration of one month. A weekly sample was thenremoved from the oven, allowed to equilibrate to room temperature,residual cure and UCS were then determined. Table 8 summarizes theresults of these tests on the prepared samples.

TABLE 8 Time (week) Results 0 Baseline 1 No change from Baseline 2 Nochange from Baseline 3 No change from Baseline 4 No change from Baseline

140° F. Extended Storage Stability Test

In order to test whether or not the resin-coated proppant particulateswould consolidate or the finished properties would change under elevatedstorage conditions in the absence of an activator, samples of CARBOBONDLITE 20/40 resin-coated lightweight ceramic proppant, which iscommercially available from CARBO Ceramics, Inc., were heated in an ovenset at 140° F. for a duration of 365 days. Samples were periodicallyremoved from the oven, allowed to equilibrate to room temperature, andUCS at 250° F. and closure stress of 1000 psi was then determined. Thesamples maintained a UCS of about 1,010 psi for about 365 days andpossessed a UCS ranging from about 950 psi to about 1,010 psi for aboutthe last 100 days of the 365 day test.

Cure Kinetics

In order to determine the working time or the time it takes theproppant/fluid mixture to reach a viscosity where it becomes unworkable,samples of CarboBond®Lite® 20/40 resin-coated lightweight ceramicproppant, which is commercially available from CARBO Ceramics, Inc.,were exposed to an 80 pound HEC fluid with 1.5% Vicon NF (breaker) and2% D.E.R.^(TM) 3913 Epoxy Resin (activator) at 100° F., 130° F., 150°F., 175° F. and 200° F. Samples were then removed at different timepoints and the UCS was determined. Table 9 summarizes the results ofthese tests on the prepared samples.

TABLE 9 Working Life Temperature (hr) 100° F. 24-48 130° F. 12-18 150°F. 3-4 175° F. 1.5-2  200° F.  1-1.5

The data in Table 9 shows that the proppant/fluid mixture remainsflowable/pumpable for up to 1.5 hr, 1.5-2 hr, 3-4 hr, 12-18 hr and 24-48hr at 200° F., 175° F., 150° F., 130° F. and 100° F., respectively.

Consolidation Test

In order to test whether or not the resin-coated proppant particulateswould consolidate under wellbore conditions in the absence of anactivator, three fracturing fluid proppant samples which contained 1% byweight of the epoxy dispersion of Ancarez® AR555 Epoxy Resin, Ancarez®AR462 Resin and D.E.R.™ 916 Epoxy Resin were prepared. The samples wereprepared using the procedure outlined above. The samples were takenafter 0.12 g of the peroxydisulfate breaker was added to the mixture.The hot plate procedures were not used to avoid breaking the fracturingfluid.

A proppant slug sample that included the Ancarez® AR555 Epoxy Resin,Ancarez® AR462 Resin and D.E.R™ 916 Epoxy Resin epoxy dispersions wereplaced into glass jars and heated to 200° F. for 48 hours. After 48hours, the proppant was observed for consolidation. Table 10 summarizesthe results of the consolidation tests.

TABLE 10 Sample Observation Ancarez ® AR555 Unconsolidated Epoxy ResinAncarez ® AR462 Unconsolidated Resin D.E.R. ™ 916 Unconsolidated EpoxyResin

This data shows that the proppant samples remained unconsolidated in thepresence of unbroken fracturing fluid, indicating that the resin-coatedproppant particulates will remain unconsolidated under wellboreconditions.

Activator and Borate Crosslinker Compatibility

In order to test whether or not a borate crosslinker would be compatiblewith an activator, two fracturing fluid samples in which contained 2 and3% FDP-601 activator were run on a Chandler HPTP Viscometer Model 5550and were compared to the base cross-linked InstaVis™ gel. InstaVis is afracturing fluid that is commercially available from Halliburton EnergyServices, Inc. The FDP-601 activator is a two component blend of D.E.R.3913 and D.E.R. 732. FIG. 7 depicts a graphical representation showingthe effect of the addition of the FDP-601 activator to cross-linked gelon a rheology profile of the cross-linked gel. As shown in FIG. 7, theaddition of the FDP-601 activator to the cross-linked gel at 2-3% doesnot affect the rheology profile of the cross-linked gel.

Exemplary embodiments of the present disclosure further relate to anyone or more of the following paragraphs:

1. A method of gravel packing a wellbore, the method comprising: mixingan activator, a thickener, a crosslinker, and a plurality ofresin-coated proppant particulates to provide a gravel pack fluid;introducing the gravel pack fluid into a gravel pack region of thewellbore; and consolidating at least a portion of the plurality ofresin-coated proppant particulates to provide a consolidated gravelpack, wherein the consolidated gravel pack has a UCS of at least about60 psi when formed under a pressure of about 0.01 psi to about 50 psiand a temperature of about 160° F. to about 250° F.

2. The method according to paragraph 1, wherein the gravel pack fluid isobtained by: providing an aqueous solution containing a breaker, theactivator and the thickener; mixing the plurality of resin-coatedproppant particulates with the aqueous solution to provide a slurry; andadding the crosslinker to the slurry to provide the gravel pack fluid.

3. The method according to paragraph 1, wherein the gravel pack fluid isobtained by: providing a slurry containing the plurality of resin-coatedproppant particulates; mixing the activator with the slurry to providean activated slurry; and adding the crosslinker to the activated slurryto provide the gravel pack fluid.

4. The method according to paragraph 1, wherein the gravel pack fluid isobtained by: providing an aqueous solution containing a breaker, theactivator and the thickener; mixing the crosslinker with the aqueoussolution to provide a base fluid; and adding the plurality ofresin-coated proppant particulates to the base fluid to provide thegravel pack fluid.

5. The method according to any one of paragraphs 1 to 4, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

6. The method according to any one of paragraphs 1 to 5, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,HEC, ethylcellulose, methylcellulose, sodium carboxymethylcellulose,hydroxypropylcellulose, and hydroxyethylcellulose, and polyacrylamidesand any combination thereof.

7. The method according to any one of paragraphs 1 to 6, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

8. The method according to any one of paragraphs 1 to 6, wherein thecrosslinker is a delayed crosslinker.

9. The method according to any one of paragraphs 1 to 8, wherein thegravel pack fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

10. The method according to any one of paragraphs 1 to 9, wherein theproppant particulates are selected from the group consisting of alightweight ceramic proppant, an intermediate strength ceramic proppant,a high strength ceramic proppant, a natural frac sand, a porous ceramicproppant and glass beads.

11. The method according to any one of paragraphs 1 to 10, wherein thecrosslinker in the gravel pack fluid increases the viscosity of thegravel pack fluid.

12. The method according to any one of paragraphs 1 to 11, wherein theresin coating comprises an amine-cured novolac resin coating.

13. The method according to paragraph 12, wherein the amine-curednovolac resin comprises a hexamine-cured novolac resin.

14. The method according to paragraph 13, wherein the resin coatingcomprises residual active amine groups.

15. The method according to any one of paragraphs 1 to 14, wherein theresin coating comprises an epoxy resin coating.

16. The method according to any one of paragraphs 1 to 15, wherein theconsolidation of at least of portion of the resin-coated proppantparticulates takes place at a temperature of less than 220° F.

17. A method of frac packing a wellbore, the method comprising: mixingan activator, a thickener, a crosslinker, and a plurality ofresin-coated proppant particulates to provide a frac pack fluid;introducing the frac pack fluid into a frac pack region of the wellboreand into a fracture of a subterranean formation adjacent to the fracpack region; and consolidating at least a portion of the plurality ofresin-coated proppant particulates to provide a consolidated frac pack,wherein the consolidated frac pack has a UCS of at least about 60 psiwhen formed under a pressure of about 0.01 psi to about 50 psi and atemperature of about 160° F. to about 250° F.

18. The method according to paragraph 17, wherein the frac pack fluid isobtained by: providing an aqueous solution containing a breaker, theactivator and the thickener; mixing the plurality of resin-coatedproppant particulates with the aqueous solution to provide a slurry; andadding the crosslinker to the slurry to provide the frac pack fluid.

19. The method according to paragraphs 17 or 18, wherein the frac packfluid is obtained by: providing a slurry containing the plurality ofresin-coated proppant particulates; mixing the activator with the slurryto provide an activated slurry; and adding the crosslinker to theactivated slurry to provide the frac pack fluid.

20. The method according to any one of paragraphs 17 to 19, wherein thefrac pack fluid is obtained by: providing an aqueous solution containinga breaker, the activator and the thickener; mixing the crosslinker withthe aqueous solution to provide a base fluid; and adding the pluralityof resin-coated proppant particulates to the base fluid to provide thefrac pack fluid.

21. The method according to any one of paragraphs 17 to 20, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

22. The method according to any one of paragraphs 17 to 21, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,mineral oil, HEC, ethylcellulose, methylcellulose, sodiumcarboxymethylcellulose, hydroxypropylcellulose, andhydroxyethylcellulose, and polyacrylamides and any combination thereof

23. The method according to any one of paragraphs 17 to 22, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

24. The method according to any one of paragraphs 17 to 23, wherein thecrosslinker is a delayed crosslinker.

25. The method according to any one of paragraphs 17 to 24, wherein thefrac pack fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

26. The method according to any one of paragraphs 17 to 25, wherein theproppant particulates are selected from the group consisting of alightweight ceramic proppant, an intermediate strength ceramic proppant,a high strength ceramic proppant, a natural frac sand, a porous ceramicproppant and glass beads.

27. The method according to any one of paragraphs 17 to 26, wherein theresin coating comprises an amine-cured novolac resin coating.

28. The method according to paragraph 27, wherein the amine-curednovolac resin comprises a hexamine-cured novolac resin.

29. The method according to paragraph 28, wherein the resin coatingcomprises residual active amine groups.

30. The method according to any one of paragraphs 17 to 29, wherein theresin coating comprises an epoxy resin coating.

31. The method according to any one of paragraphs 17 to 30, wherein theconsolidation of at least of portion of the resin-coated proppantparticulates takes place at a temperature of less than 200° F.

32. A method of hydraulic fracturing of a subterranean formation, themethod comprising: mixing an activator, a thickener, a crosslinker, anda plurality of resin-coated proppant particulates to provide afracturing fluid; contacting a subterranean formation with thefracturing fluid so as to create or enhance one or more fractures in thesubterranean formation; depositing the plurality of resin-coatedproppant particulates in at least one or more of the fractures; breakingthe fracturing fluid; and consolidating at least a portion of theplurality of resin-coated proppant particulates to provide aconsolidated proppant pack, wherein the consolidated proppant pack has aUCS of at least about 60 psi under a pressure of about 0.01 psi to about50 psi and a temperature of about 160° F. to about 250° F.

33. The method according to paragraph 32, wherein the fracturing fluidis obtained by: providing an aqueous solution containing a breaker, theactivator and the thickener; mixing the plurality of resin-coatedproppant particulates with the aqueous solution to provide a slurry; andadding the crosslinker to the slurry to provide the fracturing fluid.

34. The method according to paragraph 32, wherein the fracturing fluidis obtained by: providing a slurry containing the plurality ofresin-coated proppant particulates; mixing the activator with the slurryto provide an activated slurry; and adding the crosslinker to theactivated slurry to provide the fracturing fluid.

35. The method according to paragraph 32, wherein the fracturing fluidis obtained by: providing an aqueous solution containing a breaker, theactivator and the thickener; mixing the crosslinker with the aqueoussolution to provide a base fluid; and adding the plurality ofresin-coated proppant particulates to the base fluid to provide thefracturing fluid.

36. The method according to any one of paragraphs 32 to 36, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

37. The method according to any one of paragraphs 32 to 36, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,mineral oil, HEC, ethylcellulose, methylcellulose, sodiumcarboxymethylcellulose, hydroxypropylcellulose, andhydroxyethylcellulose, and polyacrylamides and any combination thereof

38. The method according to any one of paragraphs 32 to 37, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

39. The method according to any one of paragraphs 32 to 38, wherein thecrosslinker is a delayed crosslinker.

40. The method according to any one of paragraphs 32 to 39, wherein thefracturing fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

41. The method according to any one of paragraphs 32 to 40, wherein theproppant particulates are selected from the group consisting of alightweight ceramic proppant, an intermediate strength ceramic proppant,a high strength ceramic proppant, a natural frac sand, a porous ceramicproppant and glass beads.

42. The method according to any one of paragraphs 32 to 41, wherein thecrosslinker in the fracturing fluid increases the viscosity of thefracturing fluid.

43. The method according to any one of paragraphs 32 to 42, wherein theresin coating comprises an amine-cured novolac resin coating.

44. The method according to paragraph 43, wherein the amine-curednovolac resin comprises a hexamine-cured novolac resin.

45. The method according to any one of paragraphs 32 to 44, wherein theresin coating comprises residual active amine groups.

46. The method according to any one of paragraphs 32 to 45, wherein theresin coating comprises an epoxy resin coating.

47. The method according to any one of paragraphs 32 to 46, wherein theconsolidation of at least of portion of the resin-coated proppantparticulates takes place at a temperature of less than 200° F.

48. A ceramic proppant composition, comprising: a plurality of porousceramic proppant particulates; an activator infused in the porousceramic proppant particulates; and a resin coated onto outer surfaces ofthe porous ceramic proppant particulates.

49. The ceramic proppant composition according to paragraph 48, whereinthe plurality of porous ceramic particulates have a porosity from about1% to about 75%.

50. The ceramic proppant composition according to paragraphs 48 or 49,wherein the activator is selected from the group consisting of waterdispersible liquid epoxy resin, a water dispersible solid epoxy resin,and an amine-rich resin and any mixture thereof.

51. The ceramic proppant composition according to any one of paragraphs48 to 50, wherein the activator is selected from the group consisting ofD.E.R. 3913, D.E.R. 732, and D.E.R. 736 and any mixture thereof

52. The ceramic proppant composition according to any one of paragraphs48 to 50, wherein the resin-coating comprises an amine-cured novolacresin coating.

53. The ceramic proppant composition according to paragraph 52, whereinthe amine-cured novolac resin coating comprises a hexamine-cured novolacresin.

54. The ceramic proppant composition according to paragraph 53, whereinthe resin coating comprises residual active amine groups.

55. The ceramic proppant composition according to any one of paragraphs48 to 54, wherein the activator elutes from the porous ceramic proppantparticulates at a rate of at least about 0.5 ppm/(gram*day).

56. The ceramic proppant composition according to paragraph 55, whereinthe activator eluted from the porous ceramic proppant particulates hasan affinity for the resin coating of the proppant particulates.

57. A method of gravel packing a wellbore, the method comprising: mixinga thickener, a crosslinker, and the ceramic proppant composition ofclaim 48 to provide a gravel pack fluid; introducing the gravel packfluid into a gravel pack region of the wellbore; and consolidating atleast a portion of the ceramic proppant composition to provide aconsolidated gravel pack, wherein the consolidated gravel pack has a UCSof at least about 60 psi under a pressure of about 0.01 psi to about 50psi and a temperature of about 160° F. to about 250° F.

58. The method according to paragraph 57, wherein the gravel pack fluidis obtained by: providing an aqueous solution containing a breaker andthe thickener; mixing the ceramic proppant composition with the aqueoussolution to provide a slurry; and adding the crosslinker to the slurryto provide the gravel pack fluid.

59. The method according to paragraph 57, wherein the gravel pack fluidis obtained by: providing a slurry containing the ceramic proppantcomposition; and adding the crosslinker to the slurry to provide thegravel pack fluid.

60. The method according to paragraph 57, wherein the gravel pack fluidis obtained by: providing an aqueous solution containing a breaker andthe thickener; mixing the crosslinker with the aqueous solution toprovide a base fluid; and adding the ceramic proppant composition to thebase fluid to provide the gravel pack fluid.

61. The method according to any one of paragraphs 57 to 60, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

62. The method according to any one of paragraphs 57 to 61, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,HEC, ethylcellulose, methylcellulose, sodium carboxymethylcellulose,hydroxypropylcellulose, and hydroxyethylcellulose, and polyacrylamidesand any combination thereof.

63. The method according to any one of paragraphs 57 to 62, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

64. The method according to any one of paragraphs 57 to 63, wherein thecrosslinker is a delayed crosslinker.

65. The method according to any one of paragraphs 57 to 64, wherein thegravel pack fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

66. The method according to any one of paragraphs 57 to 65, wherein thecrosslinker in the gravel pack fluid increases the viscosity of thegravel pack fluid.

67. The method according to any one of paragraphs 57 to 66, wherein theresin coating comprises an amine-cured novolac resin coating.

68. The method according to paragraph 67, wherein the amine-curednovolac resin comprises a hexamine-cured novolac resin.

69. The method according to paragraph 68, wherein the resin coatingcomprises residual active amine groups.

70. The method according to any one of paragraphs 57 to 69, wherein theresin coating comprises an epoxy resin coating.

71. The method according to any one of paragraphs 57 to 70, furthercomprising eluting the activator from the porous ceramic proppantparticulates and onto the resin coating to cause the consolidation ofthe at least a portion of the ceramic proppant composition.

72. The method according to paragraph 71, wherein the activator elutesfrom the porous ceramic proppant particulates at a rate of at leastabout 0.5 ppm/(gram*day).

73. The method according to paragraph 72, wherein the activator elutedfrom the porous ceramic proppant particulates has an affinity for theresin coating.

74. The method according to paragraph 71, wherein the consolidation ofat least of portion of the resin-coated proppant particulates takesplace at a temperature of less than 200° F.

75. A method of frac packing a wellbore, the method comprising: mixing athickener, a crosslinker, and the ceramic proppant composition of claim48 to provide a frac pack fluid; introducing the frac pack fluid into afrac pack region of the wellbore and into a fracture of a subterraneanformation adjacent to the frac pack region; and consolidating at least aportion of the ceramic proppant composition to provide a consolidatedfrac pack, wherein the consolidated frac pack has a UCS of at leastabout 60 psi under a pressure of about 0.01 psi to about 50 psi and atemperature of about 160° F. to about 250° F.

76. The method according to paragraph 75, wherein the frac pack fluid isobtained by: providing an aqueous solution containing a breaker and thethickener; mixing the ceramic proppant composition with the aqueoussolution to provide a slurry; and adding the crosslinker to the slurryto provide the frac pack fluid.

77. The method according to paragraph 75, wherein the frac pack fluid isobtained by: providing a slurry containing the ceramic proppantcomposition; and adding the crosslinker to the slurry to provide thefrac pack fluid.

78. The method according to paragraph 75, wherein the frac pack fluid isobtained by: providing an aqueous solution containing a breaker and thethickener; mixing the crosslinker with the aqueous solution to provide abase fluid; and adding the ceramic proppant composition to the basefluid to provide the frac pack fluid.

79. The method according to any one of paragraphs 75 to 78, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

80. The method according to any one of paragraphs 75 to 79, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,HEC, ethylcellulose, methylcellulose, sodium carboxymethylcellulose,hydroxypropylcellulose, and hydroxyethylcellulose, and polyacrylamidesand any combination thereof.

81. The method according to any one of paragraphs 75 to 80, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

82. The method according to any one of paragraphs 75 to 81, wherein thecrosslinker is a delayed crosslinker.

83. The method according to any one of paragraphs 75 to 82, wherein thefrac pack fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

84. The method according to any one of paragraphs 75 to 83, wherein theresin coating comprises an amine-cured novolac resin coating.

85. The method according to any one of paragraphs 75 to 84, wherein theamine-cured novolac resin comprises a hexamine-cured novolac resin.

86. The method according to any one of paragraphs 75 to 85, wherein theresin coating comprises residual active amine groups.

87. The method according to any one of paragraphs 75 to 86, wherein theresin coating comprises an epoxy resin coating.

88. The method according to any one of paragraphs 75 to 87, furthercomprising eluting the activator from the porous ceramic proppantparticulates and onto the resin coating to cause the consolidation ofthe at least a portion of the ceramic proppant composition.

89. The method according to paragraph 88, wherein the activator elutesfrom the porous ceramic proppant particulates at a rate of at leastabout 0.5 ppm/(gram*day).

90. The method according to paragraph 89, wherein the activator elutedfrom the porous ceramic proppant particulates has an affinity for theresin coating.

91. The method according to paragraph 88, wherein the consolidation ofat least of portion of the resin-coated proppant particulates takesplace at a temperature of less than 200° F.

92. A method of hydraulic fracturing of a subterranean formation, themethod comprising: mixing a thickener, a crosslinker, and the ceramicproppant composition of claim 48 to provide a fracturing fluid;contacting a subterranean formation with the fracturing fluid so as tocreate or enhance one or more fractures in the subterranean formation;depositing the plurality of resin-coated proppant particulates in atleast one or more of the fractures; breaking the fracturing fluid; andconsolidating at least a portion of the ceramic proppant composition toprovide a consolidated proppant pack, wherein the consolidated proppantpack has a UCS of at least about 60 psi under a pressure of about 0.01psi to about 50 psi and a temperature of about 160° F. to about 250° F.

93. The method according to paragraph 92, wherein the fracturing fluidis obtained by: providing an aqueous solution containing a breaker andthe thickener; mixing the ceramic proppant composition with the aqueoussolution to provide a slurry; and adding the crosslinker to the slurryto provide the fracturing fluid.

94. The method according to paragraph 92, wherein the fracturing fluidis obtained by: providing a slurry containing the ceramic proppantcomposition; and adding the crosslinker to the slurry to provide thefracturing fluid.

95. The method according to paragraph 92, wherein the fracturing fluidis obtained by: providing an aqueous solution containing a breaker andthe thickener; mixing the crosslinker with the aqueous solution toprovide a base fluid; and adding the ceramic proppant composition to thebase fluid to provide the fracturing fluid.

96. The method according to any one of paragraphs 92 to 95, wherein theactivator is selected from the group consisting of D.E.R. 3913, D.E.R.732, and D.E.R. 736 and any mixture thereof.

97. The method according to any one of paragraphs 92 to 96, wherein thethickener is selected from the group consisting of guar, guar gum,xanthan gum, locust bean gum, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxypropyl guar, starches, polysaccharides, alginates,HEC, ethylcellulose, methylcellulose, sodium carboxymethylcellulose,hydroxypropylcellulose, and hydroxyethylcellulose, and polyacrylamidesand any combination thereof.

98. The method according to any one of paragraphs 92 to 97, wherein thecrosslinker comprises boron, zirconium, titanium, chromium, iron, oraluminum or any combination thereof.

99. The method according to any one of paragraphs 92 to 98, wherein thecrosslinker is a delayed crosslinker.

100. The method according to any one of paragraphs 92 to 99, wherein thefracturing fluid further comprises a buffer that delays crosslinking ofthe thickener for about 30 seconds to about 5 minutes.

101. The method according to any one of paragraphs 92 to 100, whereinthe proppant particulates are selected from the group consisting of alightweight ceramic proppant, an intermediate strength ceramic proppant,a high strength ceramic proppant, a natural frac sand, a porous ceramicproppant and glass beads.

102. The method according to any one of paragraphs 92 to 101, whereinthe crosslinker in the fracturing fluid increases the viscosity of thefracturing fluid.

103. The method according to any one of paragraphs 92 to 102, whereinthe resin coating comprises an amine-cured novolac resin coating.

104. The method according to paragraph 103, wherein the amine-curednovolac resin comprises a hexamine-cured novolac resin.

105. The method according to paragraph 103, wherein the resin coatingcomprises residual active amine groups.

106. The method according to any one of paragraphs 92 to 105, whereinthe resin coating comprises an epoxy resin coating.

107. The method according to any one of paragraphs 92 to 105, furthercomprising eluting the activator from the porous ceramic proppantparticulates and onto the resin coating to cause the consolidation ofthe at least a portion of the ceramic proppant composition.

108. The method according to paragraph 107, wherein the activator elutesfrom the porous ceramic proppant particulates at a rate of at leastabout 0.5 ppm/(gram*day).

109. The method according to paragraph 108, wherein the activator elutedfrom the porous ceramic proppant particulates has an affinity for theresin coating.

110. The method according to paragraph 107, wherein the consolidation ofat least of portion of the resin-coated proppant particulates takesplace at a temperature of less than 200° F.

While the present invention has been described in terms of certainembodiments, those of ordinary skill in the art will recognize that theinvention can be practiced with modification within the spirit and scopeof the appended claims.

The present disclosure has been described relative to several exemplaryembodiments. Improvements or modifications that become apparent topersons of ordinary skill in the art only after reading this disclosureare deemed within the spirit and scope of the application. It isunderstood that several modifications, changes and substitutions areintended in the foregoing disclosure and in some instances some featuresof the invention will be employed without a corresponding use of otherfeatures. Accordingly, it is appropriate that the appended claims beconstrued broadly and in a manner consistent with the scope of theinvention.

What is claimed is:
 1. A method of gravel packing a wellbore, the methodcomprising: mixing an activator, a thickener, a crosslinker, and aplurality of resin-coated proppant particulates to provide a gravel packfluid; introducing the gravel pack fluid into a gravel pack region ofthe wellbore; and consolidating at least a portion of the plurality ofresin-coated proppant particulates to provide a consolidated gravelpack, wherein the consolidated gravel pack has a UCS of at least about60 psi when formed under a pressure of about 0.01 psi to about 50 psiand a temperature of about 160° F. to about 250° F.
 2. The method ofclaim 1, wherein the gravel pack fluid is obtained by: providing anaqueous solution containing, a breaker, the activator and the thickener;mixing the plurality of resin-coated proppant particulates with theaqueous solution to provide a slurry; and adding the crosslinker to theslurry to provide the gravel pack fluid.
 3. The method of claim 1,wherein the gravel pack fluid is obtained by: providing a slurrycontaining the plurality of resin-coated proppant particulates; mixingthe activator and a breaker with the slurry to provide an activatedslurry; and adding the crosslinker to the activated slurry to providethe gravel pack fluid.
 4. The method of claim 1, wherein the gravel packfluid is obtained by: providing an aqueous solution containing abreaker, the activator and the thickener; mixing the crosslinker withthe aqueous solution to provide a base fluid; and adding the pluralityof resin-coated proppant particulates to the base fluid to provide thegravel pack fluid.
 5. The method of claim 1, wherein the activatorcomprises one or more flexible epoxy resins.
 6. The method of claim 1,wherein the thickener is selected from the group consisting of guar,guar gum, xanthan gum, locust bean gum, hydroxypropyl guar,carboxymethyl guar, carboxymethylhydroxypropyl guar, starches,polysaccharides, alginates, HEC, ethylcellulose, methylcellulose, sodiumcarboxymethylcellulose, hydroxypropylcellulose, andhydroxyethylcellulose, and polyacrylamides and any combination thereof7. The method of claim 1, wherein the crosslinker comprises boron,zirconium, titanium, chromium, iron, or aluminum or any combinationthereof.
 8. The method of claim 1, wherein the crosslinker is a delayedcrosslinker.
 9. The method of claim 2, where the breaker comprises apersulfate, encapsulated persulfate, or ammonia or any combinationthereof.
 10. The method of claim 1, wherein the gravel pack fluidfurther comprises a buffer that delays crosslinking of the thickener forabout 30 seconds to about 5 minutes.
 11. The method of claim 1, whereinthe proppant particulates are selected from the group consisting of alightweight ceramic proppant, an intermediate strength ceramic proppant,a high strength ceramic proppant, a natural frac sand, a porous ceramicproppant and glass beads.
 12. The method of claim 1, wherein thecrosslinker in the gravel pack fluid increases the viscosity of thegravel pack fluid.
 13. The method of claim 1, wherein the resin coatingcomprises an amine-cured novolac resin coating.
 14. The method of claim13, wherein the amine-cured novolac resin comprises a hexamine-curednovolac resin.
 15. The method of claim 13, wherein the resin coatingcomprises residual active amine groups.
 16. The method of claim 1,wherein the resin coating comprises an epoxy resin coating.
 17. Themethod of claim 1, wherein the consolidation of at least of portion ofthe resin-coated proppant particulates takes place at a temperature ofless than 200° F.
 18. A ceramic proppant composition, comprising: aplurality of porous ceramic proppant particulates; an activator infusedin the porous ceramic proppant particulates; and a resin coated ontoouter surfaces of the porous ceramic proppant particulates.
 19. Theceramic proppant composition of claim 18, wherein the activator isselected from the group consisting of a water dispersible liquid epoxyresin, a water dispersible solid epoxy resin, an amine-rich resin, and aflexible epoxy resin, and any mixture thereof and wherein the resincomprises an amine-cured novalac resin.
 20. A method of gravel packing awellbore, the method comprising: mixing a thickener, a crosslinker, andthe ceramic proppant composition of claim 18 to provide a gravel packfluid; introducing the gravel pack fluid into a gravel pack region ofthe wellbore; and consolidating at least a portion of the ceramicproppant composition to provide a consolidated gravel pack, wherein theconsolidated gravel pack has a UCS of at least about 60 psi when formedunder a pressure of about 0.01 psi to about 50 psi and a temperature ofabout 160° F. to about 250° F., wherein the activator elutes from theporous ceramic proppant particulates at a rate of at least about 0.5ppm/(gram*day).